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22-327 PS 2005

THE VAST NORTH AMERICAN

RESOURCE POTENTIAL OF OIL

SHALE, OIL SANDS, AND

HEAVY OILS, PARTS 1 AND 2

OVERSIGHT HEARINGS

BEFORE THE

SUBCOMMITTEE ON ENERGY AND

MINERAL RESOURCES

OF THE

COMMITTEE ON RESOURCES

U.S. HOUSE OF REPRESENTATIVES

ONE HUNDRED NINTH CONGRESS

FIRST SESSION

June 23, 2005 and June 30, 2005

Serial No. 109-22

Printed for the use of the Committee on Resources

(

Available via the World Wide Web: http://www.gpoaccess.gov/congress/index.html

or

Committee address: http://resourcescommittee.house.gov

(II)

COMMITTEE ON RESOURCES

RICHARD W. POMBO, California, Chairman

NICK J. RAHALL II, West Virginia, Ranking Democrat Member

Don Young, Alaska

Jim Saxton, New Jersey

Elton Gallegly, California

John J. Duncan, Jr., Tennessee

Wayne T. Gilchrest, Maryland

Ken Calvert, California

Barbara Cubin, Wyoming

Vice Chair

George P. Radanovich, California

Walter B. Jones, Jr., North Carolina

Chris Cannon, Utah

John E. Peterson, Pennsylvania

Jim Gibbons, Nevada

Greg Walden, Oregon

Thomas G. Tancredo, Colorado

J.D. Hayworth, Arizona

Jeff Flake, Arizona

Rick Renzi, Arizona

Stevan Pearce, New Mexico

Henry Brown, Jr., South Carolina

Thelma Drake, Virginia

Luis G. Fortun ̃ o, Puerto Rico

Cathy McMorris, Washington

Bobby Jindal, Louisiana

Louie Gohmert, Texas

Marilyn N. Musgrave, Colorado

Vacancy

Dale E. Kildee, Michigan

Eni F.H. Faleomavaega, American Samoa

Neil Abercrombie, Hawaii

Solomon P. Ortiz, Texas

Frank Pallone, Jr., New Jersey

Donna M. Christensen, Virgin Islands

Ron Kind, Wisconsin

Grace F. Napolitano, California

Tom Udall, New Mexico

Rau ́l M. Grijalva, Arizona

Madeleine Z. Bordallo, Guam

Jim Costa, California

Charlie Melancon, Louisiana

Dan Boren, Oklahoma

George Miller, California

Edward J. Markey, Massachusetts

Peter A. DeFazio, Oregon

Jay Inslee, Washington

Mark Udall, Colorado

Dennis Cardoza, California

Stephanie Herseth, South Dakota

Steven J. Ding, Chief of Staff

Lisa Pittman, Chief Counsel

James H. Zoia, Democrat Staff Director

Jeffrey P. Petrich, Democrat Chief Counsel

SUBCOMMITTEE ON ENERGY AND MINERAL RESOURCES

JIM GIBBONS, Nevada, Chairman

RAU ́ L M. GRIJALVA, Arizona, Ranking Democrat Member

Don Young, Alaska

Barbara Cubin, Wyoming

Chris Cannon, Utah

John E. Peterson, Pennsylvania

Stevan Pearce, New Mexico

Thelma Drake, Virginia

Bobby Jindal, Louisiana

Louie Gohmert, Texas

Richard W. Pombo, California, ex officio

Eni F.H. Faleomavaega, American Samoa

Solomon P. Ortiz, Texas

Jim Costa, California

Charlie Melancon, Louisiana

Dan Boren, Oklahoma

Edward J. Markey, Massachusetts

Nick J. Rahall II, West Virginia, ex officio

(III)

CONTENTS

Page

Hearing held on Thursday, June 23, 2005 ............................................................ 1

Statement of Members:

Cannon, Hon. Chris, a Representative in Congress from the State of

Utah ............................................................................................................... 39

Prepared statement of ............................................................................... 39

Cubin, Hon. Barbara, a Representative in Congress from the State of

Wyoming, Prepared statement of ................................................................ 40

Gibbons, Hon. Jim, a Representative in Congress from the State of

Nevada ........................................................................................................... 1

Prepared statement of ............................................................................... 3

Grijalva, Hon. Rau ́l M., a Representative in Congress from the State

of Arizona ...................................................................................................... 4

Prepared statement of ............................................................................... 5

Statement of Witnesses:

George, Russell, Executive Director, Colorado Department of Natural

Resources ....................................................................................................... 51

Prepared statement of ............................................................................... 52

Response to questions submitted for the record ..................................... 59

Godec, Michael, Vice President, Advanced Resources International, Inc. ... 5

Prepared statement of ............................................................................... 8

Response to questions submitted for the record ..................................... 11

McKee, Michael J., Commissioner, Uintah County, Utah ............................ 61

Prepared statement of ............................................................................... 63

Response to questions submitted for the record ..................................... 66

O’Connor, Terry, Vice President, External and Regulatory Affairs, Shell

Unconventional Resources Energy .............................................................. 18

Prepared statement of ............................................................................... 21

Response to questions submitted for the record ..................................... 27

Savage, Jack S., President, Oil-Tech, Inc. ...................................................... 14

Prepared statement of ............................................................................... 16

Stringham, Greg, Vice President, Markets & Fiscal Policy, Canadian

Association of Petroleum Producers (CAPP) ............................................... 30

Prepared statement of ............................................................................... 32

Response to questions submitted for the record ..................................... 33

Additional materials supplied:

Department of Energy, Government of Alberta, Canada, Statement

submitted for the record ............................................................................... 69

Granados, Juan Antonio, President, Shale Oil Information Center, Inc.

Statement submitted for the record ............................................................ 49

Mathis, Mark, Executive Director, Citizens’ Alliance for Responsible

Energy, Statement submitted for the record .............................................. 75

Smith, Murray, Former Minister of Energy, Canada, Oral statement of .... 36

(V)

CONTENTS

Page

Hearing held on Thursday, June 30, 2005 ............................................................ 81

Statement of Members:

Gibbons, Hon. Jim, a Representative in Congress from the State of

Nevada ........................................................................................................... 81

Prepared statement of ............................................................................... 82

Grijalva, Hon. Rau ́l M., a Representative in Congress from the State

of Arizona, Prepared statement of ............................................................... 105

Statement of Witnesses:

Barna, Dr. Theodore K., Ph.D., Assistant Deputy Under Secretary of

Defense, Advanced Systems and Concepts, Office of the Secretary of

Defense, U.S. Department of Defense ......................................................... 83

Prepared statement of ............................................................................... 85

Response to questions submitted for the record ..................................... 88

Calvert, Chad, Deputy Assistant Secretary for Land and Minerals

Management, U.S. Department of the Interior .......................................... 98

Prepared statement of ............................................................................... 99

Response to questions submitted for the record ..................................... 101

Maddox, Mark, Principal Deputy Assistant Secretary for Fossil Energy,

U.S. Department of Energy .......................................................................... 90

Prepared statement of ............................................................................... 92

Response to questions submitted for the record ..................................... 95

Additional materials supplied:

Trent, Dr. Robert, Former Dean, School of Mineral Engineering,

University of Alaska-Fairbanks, Statement submitted for the record

by Dr. Daniel Fine ........................................................................................ 120

(1)

OVERSIGHT HEARING ON ‘‘THE VAST NORTH

AMERICAN RESOURCE POTENTIAL OF OIL

SHALE, OIL SANDS, AND HEAVY OILS,’’

PART 1

Thursday, June 23, 2005

U.S. House of Representatives

Subcommittee on Energy and Mineral Resources

Committee on Resources

Washington, D.C.

The Subcommittee met, pursuant to call, at 10:03 a.m., in Room

1324, Longworth House Office Building, Hon. Jim Gibbons

[Chairman of the Subcommittee] presiding. Present: Representatives Gibbons, Grijalva, Cubin, Cannon, Pearce, Drake, Jindal, and Costa.

STATEMENT OF THE HON. JIM GIBBONS, A REPRESENTATIVE

IN CONGRESS FROM THE STATE OF NEVADA

Mr. GIBBONS. The Subcommittee on Energy and Mineral Resources will come to order.

The Subcommittee is meeting today for the first of two hearings that attempt to set the record straight on the immense resource

potential of unconventional oil in North America. Today, we will

hear from resource experts, resource producers, and state and local

government representatives. Next Thursday, June 30th, we will

hear from the Departments of Interior, Energy, and Defense on

this.

I would guess that many of you in this room who have been fol- lowing the energy bill debate on Capitol Hill have heard time and

time again the misrepresentation that the U.S. has only 3 percent

of the world’s oil reserves. This myth, or distortion of the truth, has

been used by opponents to a comprehensive energy bill as a means

of persuading mainstream media and the American public that the

U.S. must reduce its oil use or continue to be held hostage to OPEC

imports.

Today, as we discuss North American oil shale, oil sands, and

heavy oils, we will learn that the U.S. is in quite the opposite position. We actually have some of the world’s largest potential oil

resources within our own borders.

According to the Department of Energy, the U.S. alone has 2 trillion—that is ‘‘trillion’’ with a ‘‘T’’—barrels of oil shale, out of some

2.6 trillion barrels of oil shale found worldwide. In addition, today’s

2

testimony will show the U.S. has 1 trillion barrels of other conventional and unconventional oil resources.

It is my understanding that Saudi Arabia has some 260 billion

barrels of proven oil reserves. And so if my math is correct, that

means the U.S. alone has almost 12 times more oil than Saudi Arabia. And this doesn’t count the vast North American potential of

Canada’s oil sands.

Competition for global oil resources is fierce, with the likes of

China and India continuing their quest for more oil to fuel their

burgeoning economies. OPEC has committed to increase production, and has now set their price target at $50 a barrel. And I only

say, it wasn’t too long ago, as we can all remember, OPEC’s price

span was set somewhere between $22 and $28 per barrel. Now

they have set it at $50 per barrel.

‘‘Should the U.S. continue to send billions of dollars overseas

each year to purchase foreign oil?’’ would be the question we should

all ask. I hope no one answered ‘‘Yes’’ to that question. The answer

is truly ‘‘No,’’ and we should not continue to send billions of dollars

overseas each year to pay for foreign oil. The answer ‘‘No’’ is

brought to us because we have enough oil of our own here at home;

and ‘‘No’’ because we should be spending that money here at home,

putting people to work, and securing our own economic and energy

future.

The major oil shale deposits, some 1.5 trillion barrels, are located

in the western U.S., in the States of Colorado, Utah, and Wyoming.

And more than 70 percent are expected to be on federally owned

and managed land.

But the U.S. does not have a commercial leasing program in

place to unlock this Federal resource potential; which is why I

worked with my colleagues on the Committee to include language

in the House energy bill to help expedite commercial oil shale production.

So, is commercial oil shale production feasible? I think the answer is ‘‘Yes.’’ And we will hear testimony on that feasibility today.

Today, oil shale, oil sands, and heavy oils are considered unconventional. And there are detractors out there who would have the

American public believe that unconventional oil shale resources are

insufficient to provide any real stable supply of oil for our future.

I would simply say that over the years technology and technological advances in the oil and gas industry have proven that unconventional resources of the past become the conventional

resources of the future. We can’t help but look to our neighbors to

the north, where Alberta’s oil sands were once just a twinkle in

some scientist’s eye. Alberta’s 1.7-trillion-barrel unconventional oil

resource is now producing more than 1 million barrels of oil per

day.

I welcome our witnesses today. I look forward to their testimony.

At this time, I would like to turn it over and recognize our Ranking

Member from Arizona, Mr. Grijalva, for any opening remarks he

may have. Mr. Grijalva.

[The prepared statement of Mr. Gibbons follows:]

3

Statement of The Honorable Jim Gibbons, Chairman,

Subcommittee on Energy and Mineral Resources

The Subcommittee meets today for the first of two hearings that attempts to set

the record straight on the immense resource potential of unconventional oil in North

America.

Today, we will hear from resource experts, resource producers, and State and local

government representatives.

Next Thursday, June 30th, we will hear from the Departments of Interior,

Energy, and Defense.

I would guess that many of you in this room who have been following the energy

bill debate on Capitol Hill have heard time and time again the misrepresentation

that the U.S. has only 3 percent of the world’s oil reserves.

This distortion of the truth has been used by opponents to a comprehensive

energy bill as a means of persuading the mainstream media and the American public that the U.S. must reduce its oil use or continue to be held hostage to OPEC

imports.

Today, as we discuss North American oil shale, oil sands, and heavy oils, we will

learn that the U.S. is in quite the opposite position—we actually have some of the

world’s largest potential oil resources within our own borders.

According to the Department of Energy, the U.S. alone has 2 trillion—yes, trillion

with a ‘‘T’’—barrels of oil shale out of some 2.6 trillion barrels of oil shale found

worldwide.

In addition, today’s testimony will show, the U.S. has 1 trillion barrels of other

conventional and unconventional oil resources.

Now, it is my understanding that Saudi Arabia has some 260 billion barrels of

proven oil reserves.

If my math is correct, that means the U.S. alone has almost 12 times more oil

than Saudi Arabia!

And this doesn’t count the vast North American potential of Canada’s oil sands.

Competition for global oil resources is fierce with the likes of China and India continuing their quest for more oil to fuel their burgeoning economies.

OPEC has committed to increase production and has now set their price target

at $50 per barrel.

Do you remember that not too long ago OPEC’s price band was set somewhere

between $22 and $28 per barrel?

Should the U.S. continue to send billions of dollars overseas each year to purchase

foreign oil?

I hope no one answered ‘‘yes’’ to that question—The answer is ‘‘no’’, we should not

continue to send billions of dollars overseas each year to pay for foreign oil.

‘‘No’’, because we have enough of our own oil here at home.

And ‘‘no’’, because we should be spending that money here at home, putting people to work and securing our own economic and energy future.

The major oil shale deposits—some 1.5 trillion barrels—are located in the Western U.S. in the states of Colorado, Utah, and Wyoming and more than 70 percent

are expected to be federally-owned.

But the U.S. does not have a commercial leasing program in place to unlock this

federal resource potential, which is why I worked with my colleagues to include language in the House energy bill to help expedite commercial oil shale production.

So, is commercial oil shale production feasible?

I believe the answer is ‘‘yes’’, and we’ll hear testimony on that feasibility today.

Today, oil shale, oil sands, and heavy oils are considered unconventional, and

there are detractors out there who would have the American public believe that unconventional oil shale resources are insufficient to provide any real, stable supply

of oil for our future.

I would simply say that over the years, technological advances in the oil and gas

industry have proven that the unconventional resource of the past becomes the conventional resource of the future.

We can’t help but look to our neighbors to the north where Alberta’s oil sands

were once just a twinkle in some scientist’s eye.

Alberta’s 1.7 trillion barrel unconventional oil resource is now producing more

than 1 million barrels of oil per day!

I welcome our witnesses today and look forward to their testimony.

At this time I would like to recognize our Ranking member from Arizona, Mr.

Grijalva, for any opening remarks he may have.

4

STATEMENT OF HON. RAU ́ L M. GRIJALVA, A REPRESENTATIVE

IN CONGRESS FROM THE STATE OF ARIZONA

Mr. GRIJALVA. Thank you, Mr. Chairman. And I join with you in

welcoming our witnesses and looking forward to their testimony.

Today’s hearing focuses on a potentially untapped domestic

energy resource, oil shale and oil sands. Industry experts say oil

shale holds great potential, with an estimated 2 to 4 trillion barrels

of oil locked in the Green River formation out West. Yet development of the resource has not come to fruition due, I believe, primarily to excessive cost.

While the USGS has estimated there are about 2 trillion barrels

of conventional recoverable oil in the world, it has done no estimates for oil shale or oil sand. Oil shale has a history in the western United States that is shaky at best. Many bold promises have

been made in the past about oil shale’s potential and about the affordability of its production, but few of them have come true so far.

As the old saying goes in Colorado, ‘‘Oil shale is the fuel of the future, and always will be.’’

In March of this year, The Wall Street Journal ran a story that

reiterated both the huge resource embedded in the shale of the

Green River region and the challenges that are involved in extracting oil from the rock.

Today, however, with oil prices at all-time highs, we see renewed

interest from industry in developing these resources. A recent

Washington Post article on oil shale mining in Canada stated that

major companies faced with tougher prospects for developing big,

new oil fields around the world are doing what was once unthinkable: sinking billions of dollars into projects to wring out deposits

of petroleum buried amid sand and clay.

While there is excitement about the prospects of development of

the resource, I join with my colleague Mark Udall of Colorado in

urging some degree of caution on the part of the Federal Government. The new technologies being developed to extract or convert

shale and sand into oil and gas should be adequately analyzed, and

the impacts of developing these resources should be assessed before

BLM launches into a full-scale leasing program. Before Congress

commits lands or financial resources to oil shale development,

there are important issues to consider, such as the potential impacts on water quality and quantity, particularly in such an arid

region.

Finally, as we have stated before, we cannot drill or mine our

way out of the current energy crisis. As 26 former national security

advisors have asserted, we would be better off recognizing the full

costs of our continuing and disproportionate dependence on oil from

any source.

While there may be nothing wrong with the BLM facilitating oil

shale development, I would hope that any taxpayer revenue or support be devoted to energy research and development that would be

spent on non-fossil-fuel energy technologies.

With that, I thank the Chairman.

[The prepared statement of Mr. Grijalva follows:]

5

Statement of The Honorable Rau ́l M. Grijalva, Ranking Democrat, Subcommittee on Energy and Mineral Resources

Today’s hearing focuses on a potentially untapped, domestic energy resource—oil shale and oil sands.

Industry experts say oil shale holds great potential with an estimated 2 to 4 tril- lion barrels of oil locked in the Green River formation out west, yet development

of the resource has not come to fruition due primarily to excessive costs. While the

USGS has estimated that there are about 2 trillion barrels of conventional recoverable oil in the world, it has done no estimates for oil shale or oil sands.

Oil shale has a history in the western United States that is shaky at best. Many bold promises have been made in the past about oil shale’s potential and about the

affordability of its production but few of them have come true so far. As the old saying goes in Colorado ‘‘oil shale is the fuel of the future, and always will be.’’ In March of this year, the Wall Street Journal ran a story that reiterated

both the huge energy resource embedded in the shale of the Green River region and

the challenges that are involved in extracting oil from rock. Today, however, with oil prices at all time highs, we see renewed interest from industry in developing these resources. A recent Washington Post article on oil shale

mining in Canada, stated that ‘‘Major companies—faced with tougher prospects for

developing big new oil fields around the world—are doing what was once unthinkable: sinking billions of dollars into projects to wring oil out of deposits of petroleum

buried amid sand and clay.’’ While there is excitement about the prospects of development of this resource, I

join my colleague, Mark Udall of Colorado, in urging some degree of caution on the

part of the federal government. The new technologies being developed to extract or

convert shale and sand into oil and gas should be adequately analyzed and the impacts of developing these resources should be assessed before the BLM launches into

a full scale leasing program.

Before the Congress commits lands or financial resources to oil shale development

there are important issues to consider, such as the potential impacts on water quality and quantity, particularly in such an arid region.

Finally, as we have stated before, we cannot drill—or mine—our way out the current energy crisis. As 26 former national security advisors have asserted, we would

be better off recognizing the full costs of our continuing and disproportionate dependence on oil from any source. While there may be nothing wrong with the BLM

facilitating oil shale development, I would hope that any taxpayer revenues devoted

to energy research and development would be spent on non-fossil fuel energy technologies.

Mr. GIBBONS. Thank you very much, Mr. Grijalva.

We will now recognize our first panel. Welcome, gentlemen. Mr.

Mike Godec, Vice President, Advanced Resources International, Incorporated; Mr. Jack Savage, President and CEO, Oil-Tech, Incorporated; Terry O’Connor, Vice President, External and Regulatory

Affairs, Shell Unconventional Resources Energy; and Greg

Stringham, Vice President, Markets and Fiscal Policy, Canadian

Association of Petroleum Producers.

Gentlemen, welcome. If you will all please rise and raise your

right hand, we have a policy to swear in our witnesses.

[Witnesses sworn.]

Mr. GIBBONS. Let the record reflect that each of the witnesses

answered in the affirmative. We will begin with Mr. Mike Godec.

Welcome, Mr. Godec. The floor is yours. We look forward to your

testimony.

STATEMENT OF MIKE GODEC, VICE PRESIDENT,

ADVANCED RESOURCES INTERNATIONAL, INC.

Mr. GODEC. Thank you very much, Mr. Chairman. Good morning. I am pleased to address this Subcommittee on the topic of increasing future domestic oil production from oil shale, oil sands,

and heavy oil.

6

As the Chairman stated, our Nation’s oil basins are mature and

in decline. In the past 20 years, domestic oil production has

dropped by 3 million barrels per day; while demand for oil has continued to grow.

However, the problem of declining domestic oil production is not

due to lack of domestic resources. Not including domestic oil shale

resources, which others testifying today can address more effectively than I, undeveloped domestic oil resources in the ground, or

in place, in the U.S. still total over 1 trillion barrels.

These resources include undiscovered conventional onshore and

offshore oil; the future growth of already discovered oil fields;

stranded light oil resources amenable to carbon dioxide enhanced

oil recovery; shallow and deep heavy oil; residual oil in transition

zones; and oil sands. These domestic resources could produce an

additional estimated 400 billion barrels of future technically recoverable oil, as shown in Table 1 of our written testimony provided

to this Subcommittee.

In addition, as stated in the opening remarks, another 2 trillion

barrels exist in U.S. oil shale deposits; primarily in Colorado, Utah,

and Wyoming, but also in lower-quality deposits in the eastern

U.S. Of this, about 400 billion barrels is of relatively high quality,

holding more than 30 gallons per ton of shale. Perhaps half of this

is technically recoverable, and would be the target for initial development efforts.

All told, this represents approximately 3 trillion barrels of remaining undeveloped oil resource in the U.S., with perhaps 600 billion barrels technically recoverable, if not yet economic.

Again, to put this in some context, according to the U.S. Geological Survey, current estimated recoverable oil reserves worldwide

total about 2.3 trillion barrels. This includes the vast reserves in

the Middle East and the former Soviet Union, and the recoverable

proportion of the massive heavy oil and oil sands deposits in

Canada and in Venezuela.

In this light, the U.S. petroleum industry faces the challenge of

developing and utilizing new concepts and technology for economically producing these challenging and more costly remaining domestic oil resources.

Now let me focus more explicitly on just two of the categories of

domestic oil resources that are the topic of today’s hearing: heavy

oil and oil sands. The U.S. still has very large volumes of undeveloped heavy oil and oil sands—sometimes called ‘‘tar sands’’—estimated at about 180 billion barrels originally in place. Of this, about

100 billion barrels exist in heavy oil reservoirs, with another 80 billion barrels in oil sand prospects. However, unlike oil shale, this

resource is quite geographically dispersed; located in California,

Alaska, Utah, Alabama, Texas, Wyoming, Arkansas, Kentucky,

Louisiana, Mississippi, and Missouri.

Application of thermal enhanced oil recovery technology, particularly steam injection, has enabled the U.S. industry to already recover and produce a significant portion of the domestic heavy oil

resource from the geologically most favorable, shallow portion of

the resource base, primarily in California and Alaska.

For example, in 2003, heavy oil production in California provided

over 500,000 barrels of production per day; and Alaska produced

7

27,000 barrels per day. To date, we have recovered about 17 billion

barrels of heavy oil, with about 2 billion barrels remaining in

proved economic reserves.

However, despite these impressive efforts by industry, the great

bulk—over 160 billion barrels of this resource—is not recoverable

with today’s technology. But based on our past work, we estimate

that with—another 30 billion barrels could become technically recoverable with modest advances in oil recovery technology.

An important characteristic of heavy oil and bitumen oil sands

is that nature, over geologic time and with heat and pressure, has

already converted these resources from a geologically immature hydrocarbon in the source rock, such as kerogen in oil shale, to crude

oil. As such, compared to oil shale, nature has taken care of half

of the challenge.

Still, because of its high viscosity, the remaining heavy oil and

oil sand resource is essentially immobile. Injection of heat or solvents, or the direct mining of the resource, is still required to efficiently recover and produce the heavy oil and tar sands.

Given their relative development challenges, however, and also

their likely timing of potential future contribution to domestic supplies, a prudent technology development strategy would be one that

focuses on the commercial production of, first, heavy oil, then oil

sands, and then oil shale.

The introduction of advanced heavy oil and oil sands technology,

including technologies such as horizontal wells and CO2-based enhanced oil recovery technologies, could provide a valuable first

start. In addition, adaptation of new technologies being tested and

applied in Canada could help further unlock the domestic heavy oil

and oil sands potential.

Of particular value would be the development and introduction

of state-of-the-art, zero-emission heavy oil and oil sands recovery

processes that could productively use the byproduct CO2 that

would otherwise be emitted to the atmosphere. Not only would this

achieve a positive net energy balance and increase domestic production, but it would provide one more market-based technology

option to encourage reducing CO2 emissions to the atmosphere.

Several steps could be taken to help overcome the barriers currently facing the development of domestic heavy oil and oil sands

resources:

First, reduce current geological, technical, and economic risks

through an aggressive program of research and field tests. Optimizing performance of current heavy oil and oil sands recovery

practices and expanding their application will help overcome these

current risks posed by these technologies.

State-Federal partnerships devoted to technology transfer could

also help address these barriers that currently inhibit the application of these technologies. Also, engaging in collaborative Canadian-U.S. efforts, such as sharing technology and conducting jointfunded field research, could help facilitate application of the best

technologies appropriate for all North American heavy oil and oil

sands resources.

Second, invest in new technology development that could lead to

higher oil recovery efficiencies and reduced costs. New models of

public-private partnerships focused on developing domestic oil

8

resources could enable the launching of key field projects to demonstrate higher oil recovery concepts and advanced technologies,

along with the zero-emissions recovery processes that I mentioned.

Third, provide risk mitigation incentives to mitigate the impacts

of potential drops in oil prices for those producers willing to try

new technologies. At the Federal level, recent modifications proposed for the Section 43 EOR tax credit could help accomplish this,

as could royalty relief for resources underlying Federal lands.

Finally, update the data and information base on domestic heavy

oil and oil sands. The initial studies of the domestic heavy oil and

oil sands—the ones still used today by Congress and other energy

policymakers and those quoted today in this testimony—were prepared by my co-author and me for the Interstate Oil and Gas Compact Commission nearly 20 years ago. Since then, much has been

learned about the domestic resource base, and significant advances

in heavy oil and oil sands extraction technology have taken place.

An up-to-date resource and technology study on domestic heavy

oil and oil sands could provide insights on formulating policies, initiatives, and technology, for more effectively and efficiently and

economically developing this large domestic oil resource.

With these actions, heavy oil and oil sands could provide an additional 500,000 barrels per day of U.S. production within ten years;

an additional 1 to 1-1/2 million barrels a day by 2025, particularly

from Alaska, California, Texas, Utah, and Wyoming.

Thank you very much for providing me the opportunity to testify

before the Subcommittee today.

[The prepared statement of Mr. Godec follows:]

Statement of Vello A. Kuuskraa (vkuuskraa@adv-res.com), President,

Michael Godec (mgodec@adv-res.com), Vice President, Advanced

Resources International, Inc.

Good afternoon. I am pleased to address the House Subcommittee on Energy and

Resources on the topic of increasing future domestic oil production from oil shale,

oil sands, and heavy oils.

Our nation’s oil basins are mature and in decline. In the past 20 years, domestic

oil production has dropped by 3 million barrels per day, while demand for oil has

continued to grow. As a result, imports now provide 60% of the oil consumed in the

U.S., with serious implications for energy security. In fact, in his recent national address on energy, President Bush stated: ‘‘Our dependence on foreign energy is like

a foreign tax on the American people. It is a tax our citizens pay every day in higher

gasoline prices and higher costs to heat and cool their homes. It’s a tax on jobs and

a tax that is increasing every year.’’

However, the problem of declining domestic oil production is not due to a lack of

domestic resources. Not including domestic oil shale resources, which others testifying today can address more effectively than I, undeveloped domestic oil resources

in the ground (in-place) in the U.S. still total over 1,000 billion barrels. These

resources include undiscovered conventional onshore and offshore oil; future growth

of already discovered oil fields (‘‘reserve growth’’); ‘‘stranded’’ light oil resources amenable to carbon dioxide enhanced oil recovery (CO2-EOR) technologies; shallow and

deep heavy oil amenable to thermal and other EOR technologies; residual oil in

transition zones; and oil sands. These domestic resources could provide an additional 400 billion barrels of future technically recoverable oil, as shown in Table 1.

The U.S. petroleum industry, as the leader in applying exploitation and EOR technology, faces the challenge of developing technology for economically producing this

more challenging—and more costly—remaining domestic oil resource.

Now, let me focus more explicitly on two of the categories of domestic oil resources

that are the topic of today’s hearing—heavy oil and oil sands. The U.S. still has very

large volumes of undeveloped heavy oil and oil sands (sometimes called ‘‘tar sands’’),

estimated at 180 billion barrels originally in-place. Of this, about 100 billion barrels

exists in heavy oil reservoirs, with another 80 billion barrels in oil sands prospects.

9

However, unlike oil shale, this resource, is geographically quite dispersed, located

in California (47 billion barrels), Alaska (44 billion barrels), Utah (19 to 32 billion

barrels), Alabama, Texas and Wyoming (each with 5 to 6 billion barrels), and numerous other states such as Arkansas, Kentucky, Louisiana, Mississippi and Missouri,

Application of thermal enhanced oil recovery (EOR), particularly steam injection,

has enabled industry to recover and produce a portion of the domestic heavy oil

resource, from the geologically most favorable, shallow portion of the resource base,

primarily in California and Alaska. For example, heavy oil production in California

provided 510,000 barrels per day, and in Alaska provided 27, 000 barrels per day

(both in 2003). While heavy oil production has been declining in California, it is

counterbalanced, somewhat by increasing production in Alaska, Figure 2. To date,

we have recovered 17 billion barrels of heavy oil, with 2 billion barrels in proved

reserves.

In spite of impressive efforts by industry, the great bulk over 160 billion barrels

of the resource in deep heavy oil reservoirs and in oil sands is not recoverable with

today’s oil recovery technology. Based on our past work, we estimate that another

30 billion barrels could become technically recoverable with advances in oil recovery

technology.

10

An important characteristic of heavy oil and the bitumen in oil sands is that

nature, over geologic time and with heat and pressure, has already converted these

resources from immature source rock, such as kerogen in oil shale, to a crude oil.

As such, compared to oil shale, nature has taken care of half of the challenge. Still,

because of its high viscosity (low API gravity), the remaining heavy oil and oil sand

resource is essentially immobile. Injection of heat or solvents, or the direct mining

of the resource, is required to efficiently recover and produce crude oil from heavy

oil and oil sands. Given the challenge, a prudent technology development strategy

would be to first address heavy oil, then oil sands, and then oil shale.

Introduction of advanced heavy oil and oil sands technology, including technologies such as horizontal wells and CO2-based enhanced oil recovery technologies,

would provide a valuable start. In addition, adaptation of new technologies being

tested in Canada, such as SAGD (steam assisted gravity drainage), VAPEX (the use

11

of a combination of solvent and heat), and the ‘‘top down combustion’’ process, could

help further unlocking the domestic heavy oil and oil sands resource potential. Of particular value would be the development and introduction of state-of-the-art

‘‘zero emission’’ heavy oil and oil sands recovery processes, which could involve an

upgrading and refining system involving gasification of heavy oil residue to produce

steam, hydrogen, and electricity, while productively using the by-product CO2 that

would otherwise be emitted to the atmosphere for recovery of deep heavy oil. Not

only would this achieve a positive energy balance, but it would provide one more

‘‘market-based’’ technology option for reducing CO2 emissions to the atmosphere. Several steps could be taken to overcome the barriers currently facing the devel- opment of domestic heavy oil and oil sand resources: • Reducing current geological, technical, and economic risks could be accomplished through an aggressive program of research and field tests. Optimizing

the performance of current heavy oil and oil sands recovery practices and expanding its application will help lower the geological, technical, and economic

risks involved with these enhanced oil recovery technologies. This was the pathway used by the DOE and the Gas Research Institute to reduce geologic and

technical risks which helped commercialize domestic unconventional gas, that

now accounts for over one-third of domestic natural gas production. State-Federal partnerships devoted to technology transfer would help address the barriers that currently inhibit the development and production of domestic heavy

oil and oil sands. Also, engaging in collaborative Canadian/U.S. efforts such as

sharing technology and conducting jointly-funded field R&D on oil sands and

heavy oil could help facilitate application of the best technologies appropriate

for U.S. heavy oil and oil sands resources. • Investments in new technology development would lead to higher oil recovery

efficiencies. New models of public-private partnerships focused on developing

domestic oil resources could enable the launching of key field projects to demonstrate higher oil recovery concepts and advanced technologies. Moreover,

demonstrating an integrated ‘‘zero emissions’’ steam, hydrogen and electricity

generation system, that provides ‘‘EOR-Ready’’ CO2 from the residue products

from heavy oil and oil sand upgrading and refining, would provide an efficient

approach toward future oil recovery.

• Providing ‘‘risk-mitigation’’ incentives to provide protection against sharp drops

in oil prices for those producers willing to try new technologies. At the Federal

level, recent modifications proposed for the Section 43 EOR tax credits could

help accomplish this, as could royalty relief for resources underlying Federal

lands. At the state level, severance tax relief could also help provide risk mitigation incentives.

• Update the data and information base on domestic heavy oil and oil sands. The

initial studies of domestic heavy oil and oil sands, and the ones still used by

Congress and other energy policy makers, and those quoted today in this testimony, were prepared by the two authors of this Congressional Testimony for

the Interstate Oil and Gas Compact Commission (IOGCC) nearly 20 years ago.

Since these past studies were conducted, much has been learned about the

resource base, and significant advances in heavy oil and oil sands extraction

technology has taken place. An up-to-date resource and technology study on domestic heavy oil and oil sands could provide insights on formulating policies,

initiatives and technology for more effectively developing this large oil resource,

helping increase domestic oil production.

With these actions, domestic heavy oil and oil sands could provide an additional

500,000 barrels per day of production in ten years, and an additional 1 to 1.5 million

barrels per day of domestic oil production by 2025, particularly from Alaska, California, Texas, Utah and Wyoming.

Thank you very much for providing us with the opportunity to testify before this

subcommittee today.

Response to Questions submitted for the record by Michael Godec. Vice

President, Advanced Resources International, Inc.

1. Am I correct in understanding your testimony to be that not counting oil shale,

the United States still has one trillion, one hundred thirty billion barrels of oil

in the ground?

Based on data published by the U.S. Geological Survey (USGS) and Minerals

Management Service (MMS), 570 billion barrels of oil in the ground exist in undiscovered conventional oil fields and from the future growth of already discovered oil

fields (‘‘reserve growth’’), assuming traditional oil recovery efficiency.

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Adding the ‘‘stranded’’ light oil resources in discovered fields amenable to CO2 en- hanced oil recovery (CO2-EOR); shallow and deep heavy oil fields amenable to thermal and other EOR; residual oil in transition zones; and domestic oil sands together

provide another 554 billion barrels of resource in the ground. The sum of these two is one trillion, one hundred twenty four billion barrels of oil in the ground. (This represents a slight modification to the preliminary numbers

submitted in our original testimony, which used rounded numbers.) All of these estimates are based on existing resource studies, as summarized (with citations) in

Table 1.

2 Am I further correct in understanding that you believe that at least 400 billion barrels of this oil should be able to be produced?

That is correct. We estimate that these domestic resources could provide an additional 400 billion barrels of future technically recoverable oil, again as shown in

Table 1. This does not imply that all of this is currently economic to produce, even

at today’s oil prices. This estimate includes 190 billion barrels of technically recoverable resources, using conventional technology, and 210 billion barrels of oil recovery

from ‘‘state-of-the-art’’ EOR technology. Moreover, the EOR recoverable numbers

would be significantly higher should technology progress occur for EOR.

3. Do these numbers include any increases for anticipated reserve growth?

Yes, as described in my answer to Question No. 1, the 1,124 billion barrels of undeveloped resources in the ground include the anticipated growth of reserves in conventional oil fields.

4. Are there any significant differences, other than quantity, between the U.S. oil

sands and the Alberta oil sands?

Alberta oil sands are ‘‘water wet’’ while the U.S. oil sands are ‘‘oil wet’’, making

the extraction of Albert oil sands considerably simpler. In addition, Alberta oil

sands, on average, tend to be a richer (in terms of barrels of resource per acre).

Nonetheless, there are some deposits in the U.S. that are of comparable quality to

some of the best deposits in Alberta.

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We believe much can be learned from cooperating with Canada on their pursuit

of advanced oil sand extraction technology, particularly for new in situ oil sand recovery technology.

5. Please prioritize the things that the Federal Government can do to ensure that at

least the 400 billion barrels of oil are produced.

The Federal Government, could, in priority order: (1) help reduce the financial

barriers associated with applying ‘‘state-of-the-art’’ exploration and production technologies through an aggressive program of field demonstrations and ‘‘risk mitigation’’ actions and incentives to encourage industry investments, (2) encourage increased private R&D investment and/or provide direct Federal R&D focused on developing new, ‘‘next generation’’ technologies that further improve the efficiency and

reduce the costs of pursuing U.S. undeveloped oil resources; and (3) update the data

and information base on domestic heavy oil and oil sands. Please see further elaboration in our answer to Question 7 below.

6. Looking at the whole range of extra heavy oils and tar sands you cite in your testimony, what do you see as the principal factors impeding development? How would

you prioritize attention among these resources and why?

Pursuing undeveloped domestic extra heavy oil and oil sands pose considerable

economic risks and technical challenges. The risks and challenges stem from a lack

of information on the actual geologic condition of the remaining resource (e.g., the

distribution and saturation of the residual oil in the reservoir’s pore space), uncertainties on how well oil recovery technology (often adapted from other settings) will

perform in a new geologic setting or basin, and the inherent volatility and uncertainty surrounding world oil prices. To date, this combination of geologic, technical

and economic risks have posed severe barriers to the full development of the remaining domestic oil resource base, particularly for deep heavy oil and oil sands.

As stated in my oral testimony, an important characteristic of heavy oil and oil

sands is that nature, over geologic time and with heat and pressure, has already

converted these resources from a geologically immature hydrocarbon in the source

rock, such as kerogen in oil shale, to a crude oil. Compared to oil shale, nature has

taken care of half of the challenge. As such, a prudent technology development

strategy would be one that pursues commercial production of first heavy oil, then

oil sands, and then oil shale.

7. What is your view regarding the future of unconventional liquid fuels, vs. conventional petroleum, i.e. what needs to happen before these unconventional oils attract investment? How do you see heavy oil and tar sands developing over the next

20 years?

In my testimony, I stated that the Federal Government could take a series of actions to overcome the barriers currently impeding the development of domestic

heavy oil and oil sands resources.

• First, reduce current geological, technical, and economic risks through an aggressive program of field tests and technology transfer. State-Federal partnerships devoted to field tests and technology transfer would help address the barriers that currently inhibit the application of these technologies. Also, engaging

in collaborative Canadian/U.S. efforts, such as sharing technology and conducting jointly-funded field R&D on oil sands and heavy oil, could keep developing new technologies appropriate for all North American heavy oil and oil

sands.

• Second, invest in research and new technology development toward higher oil

recovery efficiencies and reduced costs. New models of public-private partnerships, focused on developing ‘‘next generation’’ oil recovery technologies and

launching key field projects to demonstrate these higher oil recovery technologies, would be most important.

• Third, provide ‘‘risk-mitigation’’ incentives to mitigate the impacts of potential

future decline in oil prices for those producers willing to try new technologies.

At the Federal level, recent modifications proposed for the Section 43 EOR tax

credit could help accomplish this, as would royalty relief for resources underlying Federal lands. At the state level, severance tax relief would also provide

risk mitigation incentives.

• Finally, update the data and information base on domestic heavy oil and oil

sands. In the last 20 years, much has been learned about the domestic resource

base, and significant advances in heavy oil and oil sands extraction technology

have taken place. An up-to-date resource and technology study on domestic

heavy oil and oil sands could provide insights on formulating policies, initiatives

and technology for more effectively developing this large oil resource.

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With these actions, domestic heavy oil and oil sands could provide up to an additional 500,000 barrels per day of U.S. production in ten years, and an additional

1 million barrels per day by 2025, particularly from Alaska, California, Texas, Utah

and Wyoming. Without these actions, the contribution of domestic heavy oil and oil

sands to U.S. energy supplies will grow at a substantially slower rate, if at all.

* * * * *

In closing, I want to note that our biggest undeveloped oil resources ‘‘prize’’ will

be from applying advanced EOR technology to our undeveloped domestic oil

resources.

In the preceding paragraph we set forth the oil production that would be realized

from heavy oil and oil sands (up to 0.5 million barrels per day in 2015 and 1 million

barrels per day in 2025). Pursuing the rest of undeveloped domestic oil (the light

oil left behind after conventional oil recovery) with CO2-EOR would add an additional 1.5 million barrels per day by 2015 and 2.5 million barrels per day in 2025.

(These projections of future domestic oil production assume that the recommend actions set forth in response to Questions 5, 6 and 7 are successfully implemented.)

Together, these undeveloped resources could make a most significant reduction in

our future levels of oil imports and a most valuable addition to our economic and

energy security.

Mr. GIBBONS. Thank you very much, Mr. Godec.

We turn now to Mr. Jack Savage, President and CEO, Oil-Tech,

Incorporated. Mr. Savage, welcome here. We look forward to your

testimony.

STATEMENT OF JACK SAVAGE, PRESIDENT AND CEO,

OIL-TECH, INC.

Mr. SAVAGE. Thank you, and good morning, Mr. Chairman and

distinguished members of the Committee. My name is Jack Savage.

I am chief executive officer of a small, startup company in Utah,

Oil-Tech, Incorporated. I am pleased to have been asked to participate in this hearing and discuss this very important natural

resource—resources—of oil shale and oil sands.

You know, there is much negativity associated with failures of

the past, when companies back in the ’70s and ’80s attempted to

commercialize shale oil. I think that when we talk about failure,

sometimes we can refer to that as ‘‘succ-ailure.’’ We appreciate very

much the pioneer companies who have gone before and who identified the problems that prevented them from commercializing shale

oil. And it must be said that everyone who tried to make oil from

oil shale was successful; they just didn’t do it economically.

We have been able to take those identified problems, and solve

them one by one. So we are grateful for those who went before.

May I be so bold as to suggest that if ‘‘Black Sunday’’ had not occurred, if industry had continued to pursue the commercialization

of shale oil, this Nation might possibly not be in the foreign-oil-dependent situation that we’re in today.

We began in 1993, as a predecessor to the current Oil-Tech company, to work on these identified problems and solve them one by

one. I must emphasize that Oil-Tech is complete with the research

and development aspect of our project. We are prepared and ready

to enter into a commercial venture to produce economically shale

oil for commercial use.

I would also say that in doing so, Oil-Tech has never requested—

neither have we received—one dime from either state or Federal

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Governments. The funding for Oil-Tech has been handled completely by qualified, high-net-worth individuals.

The oil shale deposit that has been referred to this morning is

contained on about 5-1/2 million acres. And this tract of oil shale

ground is located in the areas comprised of southern Wyoming,

eastern Utah, and western Colorado. It is estimated, as has been

said, that there is in excess of 3 trillion tons of oil shale in that

area, from which it is estimated somewhere between 2 to 3 trillion

barrels of oil could be recovered.

This land that we refer to is—approximately 80 percent of it is

owned by the Federal Government. The next largest landowner

would be state governments; and the Indian tribes own some of the

ground; and then there’s some privately owned ground.

The technology that Oil-Tech has, and which I will present, has

been independently validated by two reputable engineering firms—

one out of Billings, Montana; one out of Tulsa, Oklahoma. Those

validations concern our representations of process efficiency, costper-barrel, and feasibility of up-sizing from a small commercial retort now in operation to a full-size, large commercial retort.

Our current, small-capacity retort and operation in eastern Utah

is full-sized on the vertical scale, compared to a full producing commercial retort unit. This is not a laboratory model. We felt we had

to build a full-sized scale model to validate the process and the feasibility and the economies of producing oil from shale. All we would

need to do would be to increase the footprint, or the diameter size

of the retort, to allow more rock capacity to cook in the retort at

a given time.

The retort is modular by design. It can be assembled and dismantled very quickly, and moved just as easily as a drilling rig in

conventional oil processing could be implemented and removed.

The cost of our 1,000-barrel-per-day retort is indirect—is relative

to the cost of drilling a well in the Rocky Mountain area, and

equipping the same with the proper equipment.

A 1,000-barrel-per-day retort design was chosen by us as the

most feasible relative to capital cost requirements and productivity.

If we want to produce 20,000 barrels of oil per day, we simply cluster 20 1,000-barrel-per-day units. And as I said, they are very mobile and they can be moved from one area to another area within

a week’s time, when a particular area might be mined out. This is

a mining material-handling problem. And the build-out of surface

retorts would be done so in conjunction with the build-out of an underground mine situation.

I see my time is up, and I will just conclude here quickly by saying that we use very little energy in producing the potential energy

of the shale oil. One thing that I learned as a young boy, that when

trying to absorb teachings it was much easier to do so when there

was a visual aide present. And I have made an assumption that

you can also learn more quickly by looking at a visual aide, rather

than listening to me. And I’ve made available these little display

units which, hopefully, you’ll display on your desk.

There’s a piece of oil shale. A lot of people don’t know what oil

shale is. And then the little vials represent the different stages of

the shale through the process; and then the different products that

are created thereby.

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I would just end by inviting each of you, individually or together

as a committee, to come to Utah and visit our site and let us—

bring your canteens; we’ll fill them with shale oil. And we’d be

happy to host you. Thank you very much for your time.

[The prepared statement of Mr. Savage follows:]

Statement of Jack S. Savage, President, Oil-Tech, Inc.

OIL-TECH: THE COMPANY

Oil-Tech, Inc. was incorporated in the State of Utah in February 2000. Oil-Tech

(OT/the Company) is current in meeting all state regulations and requirements and

is considered a corporation of good standing. OT is a nonoperating company which

has just completed its research and development project, has received independent

validation of its representations as to its ability to produce oil from oil shale, cost

per barrel, feasibility of up sizing to full commercial scale, efficiency of process, etc.

Patents have been filed with the U.S. Patent Office, the Patent Cooperation Treaty

(PCT) and the country of Jordan.

OT is a privately held Utah corporation formed exclusively to complete the research and development and refinement of patent pending technology which has its

roots back to the year 1993. OT’s intended purpose is to be an operating entity for

the mining of oil shale and the production of shale oil on leased oil shale acreage

currently held by the Company in order to capitalize on the Company’s patent pending shale oil production technology.

MARKET SUPPLY AND DEMAND

According to the World Energy Council, the largest oil shale reserves occur in the

United States in an area of 5.5 million acres covering northeastern Utah, northwestern Colorado and southern Wyoming. It is estimated that this area contains approximately 3.3 trillion tons, or two-thirds of the worlds’s potentially recoverable oil

shale resource. This same resource is estimated to be capable of producing more

than 2.5 trillion barrels of recoverable shale oil. These reserves contain potential oil

supplies that would completely meet the United States’ energy demands for the next

several hundred years.

The oil demand in the United States is approximately 20 million barrels per day

with a major portion of all consumption, both crude and finished product, currently

imported at a cost of over $150 billion per year, amounting to the largest single element of the United States trade deficit.

United States crude oil production capacity is estimated at 5.5 million barrels per

day (mbd) from approximately 533,000 oil wells, averaging less than 12 barrels per

well per day.

OIL-TECH ADVANTAGES

To the best of the Company’s knowledge, no other entity has a technological or

economic advantage or has developed oil shale technology to the level that Oil-Tech

has reached. Dr. Anton Damer of the Department of Energy believes OT to be 10

years ahead of any other company engaged in the commercialization of shale oil. Dr.

James Bunger, consultant to the Department of Energy on oil shale matters believes

OT to be the leader in surface oil shale retort technology.

OIL-TECH’S TECHNOLOGY AND ASSOCIATED PROCESSES

The Company currently operates a small capacity, commercial retort in eastern

Utah, approximately 40 miles southeast of Vernal, Utah. The retort has a capacity

to process one ton of oil shale per hour. On average, one ton of oil shale will produce

one barrel of shale oil. The proprietary retort produces 30 degree API gravity oil

with a pour point of 53 degrees Fahrenheit. When the nitrogen compounds are removed from the shale oil, the resulting product is very close to JP-8 fuel. The refinery ready crude is comprised of approximately 10% Naphtha, 40% Kerosene, 40%

diesel and 10% heavy residual gas oil. The entire blend is low in sulfur.

The Company’s existing, small capacity commercial retort was designed and fabricated to be full scale vertically. Full, commercial size on the vertical scale is essential to enable sufficient ‘‘soaking’’ time of the oil shale in the retort produced heat.

A less than full size laboratory model would be insufficient to prove the methodology

of OT’s proprietary technology. To move to a full capacity (1,000 barrel per day)

commercial retort, increasing the size of the ‘‘foot print’’ and adding additional heaters is all that remains. Up sizing to the full commercial scale of 1,000 barrels per

day with anticipation of equal or enhanced results of the current operating model

17

has been validated by the independent engineering firms of Unifield Engineering,

Billings, Montana, and Tulsa Combustion, LC, of Tulsa, Oklahoma. The proprietary retort is modular by design. One full capacity commercial retort can be assembled and/or disassembled as quickly and easily as a standard drilling

rig. Accordingly, it is easy and cost efficient to move these portable retorts when

an area of oil shale has been mined out.

The 1,000 barrel per day capacity retort was designed as such to be economical in the fabrication process (approximately $2 million for each retort), to be portable

and any number of retorts can be mass manufactured and clustered together to, in

combination, process the daily tonnage capacity of any given mine. For example, if

the desired oil production is 20,000 barrels per day, 20 1,000 barrel per day retorts

will be clustered together to reach the desired production rate. Additionally, if one

retort is shut down for repair or service, 19,000 barrels of oil are still being produced. Conversely, with a single, highly capital intensive 10,000 barrel per day retort, if shut down for service or repair, the loss of oil production is much more significant.

Contrary to some oil shale processes, the Company’s proprietary technology uti- lizes very little purchased energy to manufacture shale oil. Initially, the oil shale

is heated electrically. After approximately 6 hours of operation, there is sufficient

‘‘spent’’ shale to enable co-generation. The spent shale exits the retort at approximately 1,000 degrees Fahrenheit. Fixed carbon remains in the spent shale and is

combustible with the addition of air. The temperature of the spent shale is then

raised to approximately 2,500 degrees Fahrenheit. This is a sufficient heat source

to enable purchased electrical power to be turned off and new oil shale to be adequately heated with direct heat from the spent shale. Every 60 minutes approximately 41 tons of 2,500 degree spent shale is produced. This is an impressive thermal mass, to say the least. Heat is available for generating steam, heating refinery

feeds, generating electricity, etc.

Per barrel of oil production/retorting cost is $8.00 per barrel when utilizing purchased electrical heat and decreases dramatically to $4.00 per barrel when using cogenerated heat. This per barrel of oil cost considers only the retorting costs and does

not consider the mining costs. Mining costs range from $5.60 per ton of oil shale

mined to $22.00 per ton depending on the development stage of the mine and the

type of equipment utilized. Accordingly, OT’s technology and processes can produce

one barrel of shale oil at approximately $9.60 per barrel in the best case scenario

and approximately $30.00 per barrel in the worst case scenario.

The Oil-Tech technology is environmentally friendly. The retort is an oxygen free,

sealed unit under vacuum. No gases are deployed to the atmosphere. In fact, the

only non-condensed gas produced is propane. This gas is captured, processed and

is then marketable. OT would be the most environmentally friendly operation in the

eastern Utah oil shale area which is already dotted with oil and gas wells, transportation pipes on the earth’s surface, open, mined out, abandoned gilsonite veins,

abandoned structures, etc.

DISPELLING THE MYTHS

For many years, individuals and companies have wrestled with producing oil from

oil shale. Along with this knowledge, several myths evolved explaining why the production of oil from shale is seemingly ‘‘impossible.’’ These myths can be found

through any Internet search. Previous efforts have significantly assisted Oil-Tech in

attempting to overcome earlier identified problems. These out-of-date ‘‘facts’’ are dispelled by the Oil-Tech technology and development plans.

There is oil in oil shale...UNTRUE—there is no oil in oil shale, only organic material. The Oil-Tech process vaporizes this organic material and condenses this vapor

into shale oil.

The process requires huge volumes of water...UNTRUE—past efforts used water

to transport a shale oil ‘‘slush’’ through pipelines to a central processing center. The

Oil-Tech technology processes oil shale on site and does not require water in the

process. There is a nitrogen compound removal on site to separate the refinery feedstock from the asphalt additive, and water is not required in this process. Water

is required for personnel and safety use (showers, potable water, fire suppression),

and for mining operations, most of which is recyclable.

The oil shale mining costs are excessive...UNTRUE—mining is indeed required.

In the last 15 years, the technology of mining has dramatically changed and the cost

of large scale mining operations has dropped from $20 to $25 per ton of material

produced, to as low as $6 per ton, depending on depth of the mining operation. The

longwall and continuous mining technologies are key to these better economics. The

technologies were not available during the last period of heavy research and the

attempted production of oil from oil shale.

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Mining is environmentally disastrous...UNTRUE—with longwall and continuous mining technologies, very little evidence of the operation exists above ground and

the techniques allow for an easy and acceptable reclamation of the surface when operations are complete.

The technology of producing oil from oil shale is highly polluting...UNTRUE—the Oil-Tech process is completely contained, with no harmful emissions to the atmosphere. All products from the process are utilized within the sealed system. Even the

leftover spent shale has the qualities of desiccated charcoal which is used in many

ways to absorb pollutants. It is not economically feasible to produce oil from shale because of the capital re- quired...UNTRUE—early attempts by other required heavy capital expenditures on

huge facilities based on the alleged benefits of economies of scale. The Oil-Tech

process reverses that trend and uses smaller, easily replicated and fabricated modular units. These may be easily transported and assembled on site, or disassembled

for movement to another location. Any operational/service problems do not disrupt

production by more than a minimal percentage. It is not economically feasible to produce oil from shale because of the energy re- quired...UNTRUE—the Oil-Tech process has been validated to produce shale oil

with a very low energy cost. The system can also be upgraded by utilizing co-generation and a variety of BTU recovery technologies that virtually eliminate the need

for external power for any site operations. Transportation of the product is prohibitively expensive...UNTRUE—this state- ment is based on the idea piping shale oil sludge to various processing centers, involving pipelines, pumping facilities and rights-of-way disputes. It also was based

on shipping raw shale oil to potential refining centers for pre-processing prior to

normal refinery operation. The Oil-Tech process does not need to transport shale

sludge or raw shale oil to a refinery based pre-processing center. Refinery grade

feedstock is either transported in tanker trucks or injected into a local pipeline. The

asphalt additive is easily transported with heated tanker trucks. On sites where the

nitrogen extraction process will not be available, the shale oil is easily transported

in tanker trucks.

OIL-TECH HAS COMPLETED R & D

It is important to understand that the Oil-Tech technology has met the standards of independent validating engineering firms and is now poised to begin commercialization of shale oil. From the point of receiving required capital investment, OilTech can be producing 1,000 barrels of shale oil within 12 months. Production will

be at 20,000 barrels of shale oil per day at the end of a 36 month period.

INVITATION

Oil-Tech invites any and all U.S. Congressmen/Congresswomen to visit the proprietary retort site near Vernal, Utah, and experience first hand the economical production of shale oil from our nation’s vast supply of natural resource.

Mr. GIBBONS. Thank you very much, Mr. Savage. And I am sure

that these little display items will generate a couple of questions

for you later on. But we appreciate it, and it does help us immensely to have the visual aide before us.

We turn now to Mr. Terry O’Connor, Vice President, External

and Regulatory Affairs, Shell Unconventional Resources Energy.

Mr. O’Connor, welcome. The floor is yours. We look forward to your

testimony.

STATEMENT OF TERRY O’CONNOR, VICE PRESIDENT,

EXTERNAL AND REGULATORY AFFAIRS, SHELL UNCONVENTIONAL RESOURCES ENERGY

Mr. O’CONNOR. Good morning, Mr. Chairman and members of

the Committee. I’m delighted to be here today to describe to you

Shell’s initiative to develop and advance—hopefully, to commercial

success—a unique and innovative technology which we are increasingly optimistic can open up the vast oil shale resources of the

Green River Basin of northwestern Colorado, eastern Utah, and

southwestern Wyoming; which, as you have heard, contains an

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extraordinarily large quantity of potentially recoverable fossil fuels,

both oil and gas.

People talk about does it have a trillion, or 1.6 trillion, or how

much does it have. We don’t know how much is out there, because

it really depends upon the technological advances that occur over

the coming years and decades. But we are quite aware that, when

looked upon a global standpoint, roughly two-thirds of all of the oil

shale located in the world today is located in this Green River

Basin.

And it roughly equates to all—if it’s roughly a trillion barrels,

which is a report that the Department of Energy put out last year

on the strategic importance of oil shale, may very well represent

at least as much as all the discovered and proven conventional oil

resources in the world today.

This Shell technology, which we call the ‘‘In-Situ Conversion

Process,’’ or ICP as an acronym, we believe that once proven thoroughly through a next stage of development, should allow Shell to

produce clean transportation fuels of gasoline, jet fuel, and diesel,

as well as very environmentally clean natural gas, in an economically viable and environmentally sensitive manner.

Let’s talk a little bit about where we’ve been and where we’re

going for a moment. Some 23 years ago, in 1982—literally in the

shadows of the unsuccessful efforts to develop oil shale in western

Colorado and eastern Utah—Shell commenced laboratory work in

its laboratories in Houston to determine whether this in-situ conversion process technology may have merit. We continued with this

lab research for 14 years and, in 1996, successfully carried out our

first, very small-scale field experiment in Rio Blanco County, which

is located about 200 miles west of Denver.

Shell has now successfully completed four more increasingly complex, but still rather small, integrated projects; the last of which I’d

like to just take a few moments to talk about a little bit today, because we’re rather excited about the results.

We successfully produced about 1,400 barrels of oil and associated gas from a very small site that’s probably half the size of this

hearing room today, Mr. Chairman. And we were really excited

about this; not only because we were able to produce this quantity

of very light end oil and associated natural gas from such a small

site, but we were able to produce it almost in perfect harmony with

our expected modeling from a time, from a volume, and from a

quality standpoint. This gives us sufficient confidence to move to

what we hope will be our final oil shale test before hopefully making a decision by the end of this decade.

With regard to the technology itself, literally, what we are doing

is sort of the converse of what the retort technologies attempt; in

that we take the heat to the rock, rather than bringing the rock

to the heat.

What does this mean? Well, literally, what it means is we drill

quite a number of vertical holes—not very large; about the size of

a softball—vertically down into the oil shale; and we drop down

electric heaters; and we slowly heat that sub-surface resource over

a period of two, three, or four years, up to the point when the

resource itself reaches about 650 or 700 degrees, at which time

20

we’re then able to recover the light end portion of this oil, as well

as gas.

And we recover about two-thirds light end oil, and about onethird gas. We recover it in extraordinarily high volumes. We currently estimate that with this technology we’ll be able to recover

somewhere in excess of a million barrels of product per acre, or

somewhere approximately 1 billion barrels per square mile.

Talking just for a moment about the environmental impacts of

this—because this is something we’re extraordinarily proud of and

we’re happy to talk about potential environmental effects—because

the ICP process involves no mining, and thus creates no contaminated tailings, piles, or large waste disposal issues, our footprint is

considerably smaller.

It’s easier to reclaim, from a surface standpoint. We use a lot less

water. And as I indicated before, we’re thus able to penetrate

depths which other technologies may not be able to penetrate, and

thicknesses. Some of those thicknesses of oil shale in the Piceance

Basin of Colorado are in excess of 1,000-foot thick. That’s ideally

suited for our type of technology, and that is a large part of the

reason why we’re able to get these extraordinarily large recoveries.

It creates a smaller footprint because we’re able to go into these

thicker, deeper seams.

And one of the issues from an environmental standpoint about

which we are most proud is that we have developed a very robust

system for protecting the ground water. This sounds a bit counterintuitive, but before we heat the area that we are attempting to develop, we literally build an ice wall around the circumference of the

area. Ice creates an impermeable substance, and we’re able thus to

be able to contain the area of impact. That results in the prevention of offsite ground water impacts, and allows for much more efficient and expeditious ground water clean-up after the process is

completed.

Moving on, I think it’s relevant to point out that, while the

United States—and particularly, the Green River Basin of

Colorado, Utah, and Wyoming—are really the Saudi Arabia of oil

shale, oil shale is nevertheless located in a number of other countries around the world. And in fact, four countries—namely, Estonia, Brazil, China, and Australia—currently have ongoing R&D

projects for oil shale, despite the fact that their oil shale resources

are not nearly as concentrated, as rich, or as extensive. They’re all

being done with various degrees of public assistance.

We think that the time has now come for the United States to

join these other countries, to advance the technologies and develop

commercially oil shale, as long as it can be done in an environmentally sensitive and economically feasible manner.

In the interests of time, I’m not going to go into the specifics of

several recommendations that we have submitted in our written

testimony, but really would commend them to you for your

proactive and favorable consideration.

We do thank this Committee, this Subcommittee, the full

Resources Committee, and in fact the House of Representatives, for

including the first two of these recommendations in general terms

in the energy bill which you passed a couple of months ago.

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I would also mention and thank the Bureau of Land Management, Department of Interior, because they just recently took a

small but extraordinarily important step of finalizing a small research and development leasing program for oil shale. And they’ve

really done a good job in advancing this as a first step. They need

to now continue on toward commercialization in a rational manner.

And I might also add that Secretary Norton today as we speak

is at our site, viewing and being briefed on the aspects of our research and technology and where we’re attempting to go strategically. And I, too, would invite the members of this Committee, individually or collectively, to come out and look at our ongoing research.

In summary, we believe that the time has come for Congress and

this Administration to conduct appropriately targeted legislative

and regulatory measures to advance responsible oil shale development in this country. And we’re increasingly encouraged that the

Shell in-situ conversion process may very well be the first available

technology to do so on a commercial basis. Thank you very much.

[The prepared statement of Mr. O’Connor follows:]

Statement of Terry O’Connor, Vice President of External and Regulatory

Affairs, Shell Unconventional Resources Energy

Good morning Mr. Chairman and Members of the Energy and Mineral Resources

Subcommittee:

My name is Terry O’Connor. I am Vice President of External and Regulatory Affairs for the Shell Unconventional Resources unit of Shell Exploration and Production Company. I am delighted to appear before you today to describe Shell’s initiative to develop and advance, hopefully to commercial success, a unique and innovative technology which we are increasingly optimistic can open up the vast oil shale

resources in the Western United States. This technology, once thoroughly proven

technically, will allow Shell to produce clean transportation fuels such as gasoline,

jet fuel and diesel as well as clean burning natural gas from oil shale in an economically viable and very environmentally sensitive fashion. Because the oil shale

resource in the United States is extensive, this technology holds promise for significantly increasing U.S. domestic energy production.

For decades, energy companies have been trying, without success, to unlock the

large domestic oil shale resources of northwestern Colorado, eastern Utah and

southwestern Wyoming. Oil shale can be found in large parts of the Green River

Basin and is over 1,000 feet thick in many areas. According to DOE estimates, the

Basin contains in excess of 1 trillion recoverable barrels of hydrocarbons locked up

in the shale. It is thus easy to see why there have been so many attempts to unlock

this potentially enormous resource in the past.

Some 23 years ago, Shell commenced laboratory and field research on a promising

in ground conversion and recovery process. This technology is called the In-situ Conversion Process, or ICP. In 1996, Shell successfully carried out its first small field

test on its privately owned Mahogany property in Rio Blanco County, Colorado some

200 miles west of Denver. Since then, Shell has carried out four additional related

field tests at nearby sites. The most recent test was carried out over the past several

months and produced in excess of 1,400 barrels of light oil plus associated gas from

a very small test plot using the ICP technology. We are pleased with these results,

not only because oil and gas was produced, but also because it was produced in

quantity, quality and on schedule as predicted by our computer modeling. With this

successful test, Shell is now ready to begin work on the final tests that will be required to prove the technology to the point where there is sufficient certainty so as

to make a decision to proceed to commercial development.Most of the petroleum

products we consume today are derived from conventional oil fields that produce oil

and gas that have been naturally matured in the subsurface by being subjected to

heat and pressure over very long periods of time. In general terms, the In-situ Conversion Process (ICP) accelerates this natural process of oil and gas maturation by

literally tens of millions of years. This is accomplished by slow sub-surface heating

of petroleum source rock containing kerogen, the precursor to oil and gas. This

acceleration of natural processes is achieved by drilling holes into the resource,

22

inserting electric resistance heaters into those heater holes and heating the subsurface to around 650-700F. over a 3 to 4 year period. During this time, very dense

oil and gas is expelled from the kerogen and undergoes a series of changes. These

changes include the shearing of lighter components from the dense carbon compounds, concentration of available hydrogen into these lighter compounds, and

changing of phase of those lighter, more hydrogen rich compounds from liquid to

gas. In gaseous phase, these lighter fractions are now far more mobile and can move

in the subsurface through existing or induced fractures to conventional producing

wells from which they are brought to the surface. The process results in the production of about 65 to 70% of the original ‘‘carbon’’ in place in the subsurface. The carbon that does remain in the sub-surface resembles a char, is extremely hydrogen

deficient and, if brought to the surface, would require extensive energy intensive upgrading and saturation with hydrogen. Chart 1 illustrates the ICP process.

The ICP process is clearly energy intensive as its driving force is the injection of

heat into the subsurface. However, for each unit of energy used to generate power

to provide heat for the ICP process, when calculated on a life cycle basis, about 3.5

units of energy are produced and treated for sales to the consumer market. This

energy efficiency compares favorably with many conventional heavy oil fields that

for decades have used steam injection to help coax more oil out of the reservoir.

The produced hydrocarbon mix is very different from traditional crude oils. It is

much lighter and contains almost no heavy ends. Its quality can be controlled by

changing the heating time, temperature and pressure in the sub-surface. The production mix generally seen from Colorado oil shale is about two thirds liquids and

one-third natural gas and gas liquids such as propane and butane. On the liquid

product side, the typical split encountered is about 30% each of a gasoline precursor

called naphtha, jet fuel and diesel with the remaining 10% of the barrel being

slightly heavier. These fractions can be easily transformed into finished products

with significantly reduced processing when compared with traditional crude oils.

Because the ICP process occurs below ground, special care must be taken to keep

groundwater away from the process, as its influx would seriously reduce thermal efficiency. Special care must also be taken to keep the products of the process from

escaping into groundwater flows. Shell has adapted a long recognized and established mining and construction ice wall technology to isolate the active ICP area and

thus accomplish these objectives and to safe guard the environment. For years,

freezing of groundwater to form a subsurface ice barrier has been used to isolate

areas being tunneled and to reduce natural water flows into mines. Where groundwater intrusion is a problem in the ICP process, the subsurface surrounding the rich

oil shale layers is frozen to form a container of sorts, thus preventing the influx of

water while at the same time containing the products formed. Shell has successfully

tested the freezing technology and determined that the development of a freeze wall

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prevents the loss of contaminants from the heated zone. During this same test, Shell

was able to demonstrate that traditional subsurface reclamation technologies such

as steam stripping, pumping and treating and carbon bed stripping were able to remove contaminants developed in the ICP process from the subsurface to levels sufficient to meet stringent permit requirements. Though freezing the subsurface while

simultaneously heating it is clearly a counter-intuitive application of technology, it

is a good example of the creativity and unconstrained thinking that necessarily has

been a major contributor to solving potentially vexing problems in this complex Research and Development project. A schematic of the basic freezing technology is

shown in Chart 2.

Because the ICP process involves no mining, no large or contaminated tailing piles are created. Water usage is expected to be considerably less than is required

for traditional retort methods. Because the technology has the potential to recover

in excess of 1 million barrels of oil per acre in the richest parts of the Basin, or

about ten times that possible from conventional mining and retorting, temporary

land disturbance associated with ICP during production will be significantly less.

This smaller and cleaner footprint, the reduced water needs, the reduced processing

needs, a robust system for protecting groundwater from contamination and the production of clean, less Green House Gas intensive products creates an environmentally attractive package about which we at Shell are very proud. It is through well-established technologies and constant monitoring that Shell ex- pects to ensure proper and transparent stewardship of the environment. Shell is already working closely with local communities, NGOs, elected officials, and regulatory agencies to ensure that our research addresses community needs and sensitivities while ensuring strong environmental protection. Shell is currently focused on reducing the remaining risks and uncertainties that could affect the commercial viability of this technology. For this reason, Shell has

a research staff in Colorado of approximately 55 personnel in addition to approximately 100 Houston and Denver based employees assigned to the oil shale project.

The focus of these efforts is to insure the technical, commercial and environmental

viability of the technology via a relatively large integrated demonstration project.

This project would represent the final step required before a financial investment

decision would be taken by Shell for a commercial scale unit.

While Shell has spent many tens of millions of dollars on research and development for this technology and has learned a tremendous amount while reducing risk

and uncertainty, much work and expenditure still remain before the ICP process

can be commercialized. Shell is anxious to proceed with ICP research so as to help

unlock the significant potential that oil shale holds to increase indigenous energy

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supply in the United States. Achievement of this objective on a timely basis will require the active support of Congress and the Administration

Because the commercial development of oil shale would yield many benefits to the

U.S. economy, Shell supports responsible policy initiatives that will facilitate early

commercial production of shale oil and associated gas via methods that minimize

industry’s footprint and protect the environment. Shell is committed to working

with Congress, with the Department of Energy, the Department of Defense, the Department of Transportation, the Department of Homeland Security and the Department of Interior, the latter of which has stewardship responsibility over approximately 80% of the oil shale bearing lands in the Green River Basin of the Rocky

Mountain West, in order to accomplish this objective.

Key to the early development of oil shale technology is early access to appropriate

Federal oil shale deposits to allow for pilot field tests to be carried out. The leasing

of tracts of federal land to encourage research and development is an essential next

step. As a private company, Shell supports appropriate lease terms and incentives

for the development of new oil shale development technologies.

As the Department of Energy has pointed out in a recently released two volume

report entitled ‘‘Strategic Significance of America’s Oil Shale Resource’’, while oil

shale is located in many countries throughout the world, the Green River Basin of

northwestern Colorado, eastern Utah, and southwestern Wyoming contains the largest, most concentrated quantities of potentially recoverable shale oil in the world.

The Report indicates that the Basin may have as much as 1.6 trillion barrels of oil

in place, of which an estimated 1 trillion barrels ultimately may be recoverable

using various recovery technologies. This latter number is roughly equivalent to all

the combined proven conventional oil reserves in the world today, (see DOE Charts

3, 4 & 5).

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Given the size of the resource, Shell is committed to pursuing commercially and

environmentally viable technologies that can unlock the enormous potential for oil

shale that exists in the Rockies. Shell’s advancing ICP research is getting us close

to being able to help unlock these resources. We believe that successful utilization

of the ICP technology could yield substantial economic impacts to Colorado, the rest

of the Rocky Mountain West and to the United States as a whole.

26

Clearly, Shell believes there is a role for the appropriate development of oil shale deposits as part of America’s overall energy and conservation mix to meet increasing

energy demand. We are committed to the principles of Sustainable Development, to

ensuring that our activities minimize the impact on the environment, and to enhancing opportunities for local communities while facilitating our business objectives.

Ironically, despite the fact that that the United States clearly has the largest and most concentrated oil shale resources in the world, several other countries have ongoing oil shale Research and Development projects. Australia, China, Estonia and

Brazil are all progressing projects that are governmentally assisted or driven in one

fashion or another. It is Shell’s belief that the time has come for the United States

to join these other nations so as to encourage, facilitate, and accelerate the development of this potentially vast domestic energy resource. A range of options should be seriously considered in order to accelerate respon- sible U.S. oil shale development that would enhance national security and protect

our Nation’s economy. We would offer the following six recommendations for Congressional consideration. While we are not including specific legislative language, we

are eager to work with the House Resources Committee and this Subcommittee, as

well as all other relevant House and Senate Committees of jurisdiction on specific

language to create the proper mix of incentives and opportunities for accelerated,

but responsible, oil shale development.

Recommendations for Congressional consideration of six important provisions:

1. Shell believes that the U.S. government should recognize oil shale as a strate- gically important domestic energy source. We believe that Congress and the

Administration should officially support public policy initiatives that encourage

and support accelerated commercial oil shale development and use as a feedstock for transportation fuels and other products.

2. Shell believes that the Secretary of the Interior should develop a commercial oil shale leasing program on an expedited basis. We support the BLM’s recently announced R&D oil shale leasing program as an important first step in

the right direction. BLM should now be urged to implement that program on

an expedited basis.

Shell thanks the House Resources Committee and this important subcommittee for providing important leadership to the full House of Representatives for including language in the recently passed House Energy Bill that in

general terms would adopt these first two recommendations. We hope that legislative opportunities will arise in the future to give favorable consideration

to passage of language to address the next four topics. 3. Congress should act to lift the current federal acreage limitation under Title 30, Section 241(a) of the Mineral Lands Leasing Act that restricts a lessee to

acquisition of but one lease of 5,120 acres nationally. In order to facilitate commercial development for oil shale production, Shell believes that this acreage

limitation should be removed. Otherwise, companies that wish to build facilities and produce shale oil from federal lands will forever be limited to one

project. Such a limitation, which dates back to 1920, until changed will create

an impediment to even first-generation projects where the costs and risks will

be greatest. 4. Congress and the Administration should work to develop royalty rates that en- courage investment in oil shale development, giving particular recognition to

the extraordinary costs involved in literally bringing a new energy industry

into existence. In particular, Shell believes that government should develop a

royalty regime for first generation commercial oil shale production that: 1) is

simple to administer and to enforce and eliminates the need for interpretation

or the likelihood of litigation; 2) would deliver significant revenue to the U.S.

Government, and thus 50% of that amount to the impacted states; and 3)

would not involve royalty rates that so steep as to create another obstacle to

the acceleration of large-scale first generation commercial oil shale projects. 5. Shell believes that Congress and the Administration should work to ensure that an appropriate system is put in place to provide certainty and timeliness

in the permitting process for oil shale development without waiving substantive environmental performance standards. A concern is that sequential

overlay of multiple federal and state permitting processes has the potential to

add many years to what will already be a complex and protracted permitting

process.

6. Congress and the Administration should identify appropriate tax incentives

that encourage investment in oil shale technology and development, that recognize the research and development hurdles involved in oil shale technology and

development, and that appropriately treat oil shale production as the

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development of a ‘‘non-conventional resource’’ in a manner similar to other nonconventional energy resources. Specifically, where ambiguities may now exist

relative to determining whether or not in-situ oil shale recovery technologies

will qualify for tax benefits in the same manner as do existing mining tax regimes, those ambiguities should be cleared up as soon as practicable.

In summary, the United States has a huge domestic energy resource in the form

of oil shale. The time has come for Congress and this Administration to consider

appropriately targeted legislative and regulatory measures to allow oil shale to be

developed at an early date, provided that such development can occur in an economically feasible and environmentally acceptable manner. Shell is increasingly encouraged and optimistic that our ICP technology may very well represent the first

available technology to do so.

This completes my written testimony. I will be happy to respond orally or in writing to any questions any Committee member may have.

Response to questions submitted for the record by Terry O’Connor, Vice

President of External and Regulatory Affairs, Shell Unconventional

Resources Energy

1. Please tell the Subcommittee what you think the primary strengths and weaknesses are with BLM proposed R&D leasing program.

ANSWER: BLM’s final R&D leasing program provides an important and timely

first-step opportunity to tap a previously undeveloped domestic energy resource and

over time hopefully will strengthen America’s domestic energy security. Thus BLM

should be commended for initiating this important first step. The opportunity exists

to ‘‘design it right’’ in terms of developing a regulatory federal access structure that

is appropriate for this unique and abundant resource in a manner that minimizes

unrestrained ‘‘boom and bust’’ socioeconomic risks and dramatically reduces the

likelihood of environmental damage, at the same time as encouraging the advancement of new and innovative technologies to test the extraction of shale oil and gas

in a responsible manner.

The advantages of BLM’s final R&D leasing program are many, including but not

limited to the following examples:

• Establishing a framework for cautious, small scale testing of innovative shale

oil and gas recovery technologies on Federal lands.

• Providing first-of-its-kind small scale leasing of tracts up to 160 acres for appropriate shale oil recovery technologies.

• Providing a vitally important mechanism that will grant responsible operators

the eventual right to convert the small tract to a larger commercial sized tract

upon demonstrating the advancement of commercial production capability, subject to the payment of a conversion fee, NEPA compliance and obtaining necessary state and federal permits.

While BLM’s final program does not have major weaknesses, Shell does urge BLM

expeditiously to develop and finalize regulations that specify the amount of conversion fees plus the size of commercial royalties, so as to give responsible, potential

oil shale developers a degree of economic certainty as to their future obligations to

the Federal Government.

2. What does the price of oil need to be for Shell to make an acceptable profit using

the ICP process?

ANSWER: Based upon 23 years of laboratory and bench top research plus 9 years

of field research and development, Shell believes that it can make an acceptable return in a first generation commercial project with oil prices in the $25-30 per barrel

of crude price—-assuming Shell can access appropriate Federal lands, first for a

next stage R&D pilot project development and then onto commercial acreage for

larger scale operation. This crude price assumption for Shell’s ICP technology is not

currently applicable to most other Green River Basin oil shale resources. Conversely, once Shell has built and operated a first-of-its-kind commercial facility, we

believe that our future learnings should result in recovery cost reductions for subsequent second and third generation project developments by Shell or others.

3. How large does Shell think that individual lease tracts should be?

ANSWER: For initial R&D lease tracts, Shell supports the 160-acre limitation for

primary recovery operations, although we may need limited additional surface-only

use for ancillary surface support activities. For commercial-scale lease, Shell supports the 5,120-acre lease size. However, it is vitally important that Congress

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amend Section 241 of the Mineral Lands Leasing Act to allow responsible operators

to acquire more than just one oil shale lease in the United States.

4. What limitations on acreage under lease should apply to each developer, if any?

ANSWER: As noted in the answer to Question 3 above, it is critical that Congress

amend Section 241 of the MLLA to allow companies to acquire more than just one

oil shale lease nationally. While Shell sees no compelling reason to provide any

other arbitrary limits on acreage, we would not object to a 50,000-acre national

total, so long as multiple oil shale leases can be secured.

5. What royalty structure would Shell recommend?

ANSWER: Given the unique but yet undeveloped nature of commercial oil shale

production, a traditional approach to establishing an oil shale royalty is not feasible

or equitable to either side at this time. Unlike other royalty matters that BLM and

MMS have faced in the past, oil shale has never been produced in commercial quantities in the United States or elsewhere in the world. Thus there is no currently

available royalty benchmark for oil shale. Traditional oil and gas plus coal development each have a long history of operational and marketing practices to establish

both a valuation basis (gross value) as well as a rate (8%, 12 1/2%, etc.). Unlike oil

and gas, where the development and lifting costs of the product are relatively small,

oil shale development on a commercial basis inevitably will involve enormous and

speculative financial risk capital as well as very substantial ongoing operational expenses far greater than conventional oil and gas development.

It is thus critical that reasonable parameters be inserted around royalty provisions to avoid onerous regulatory revisions in the future and to assure that a royalty

methodology that meets the following criteria is met:

• A royalty that is simple to administer and to enforce and virtually eliminates

the need for interpretative litigation,

• A royalty that over time would deliver significant revenue to the U.S. Government (and thus 50% to the impacted state), and

• A royalty that would not be so large as to create another obstacle to the acceleration of large scale U.S. based commercial oil shale projects.

As a result the following royalty mechanism is recommended for the initial 20-

year primary term of a commercial oil shale lease:

Each year the royalty should be set by the Secretary at 5% of the average West

Texas Intermediate crude price (or a similar generally recognized crude price,

should the WTI be discontinued in the future) from the average of the price during

the last month of the preceding year. At the 20th anniversary of the lease, the

royalty may be readjusted based upon then applicable rules promulgated by the Secretary.

The calculation of royalty due and owing shall be established on a royalty of net

oil and hydrocarbon gas in barrels of oil equivalents produced and sold or removed

from the leased premises if no offsite processing or upgrading occurs, or from the

final point of processing or upgrading, less power fuel used in the production and

upgrading operations, said value to be measured in barrels for imported liquid

energy sources imported to the operations, and in barrels of oil equivalents from the

gaseous, solid or electrical energy imported to the lease or upgrading site.

A net royalty is needed to allow on-lease use of produced energy in the recovery

process. Furthermore, an offset for purchased power fuel should be credited given

the energy intensive nature of new evolving in-situ technologies that have the capability of recovering up to 10 times more oil and gas per acre than did traditional

retort technologies but that will require the substantial import of power to stimulate

such production. Imported power will likely represent the largest cost component for

in situ development. Thus the above-recommended provision should provide maximum flexibility to use any primary energy source.

6. What are the most important actions for the Federal Government to take in order

to ensure development of a large and vibrant oil shale production in this country?

ANSWER: As reflected in more detail in Shell’s written testimony, we believe

that the following Congressional actions should be initiated to facilitate responsible

and orderly but expedited advancement of shale oil recovery technologies:

a. The U.S. Government should officially recognize oil shale as a strategically important domestic energy fuel source.

b. The Secretary of Interior should be directed to promptly develop and implement a commercial oil shale leasing program.

c. Congress should lift the current federal acreage limitation (as noted in Answers

to Questions 3 and 4 above).

29

d. The Secretary should be directed to establish reasonable, balanced and simple royalty rates for commercial oil shale development, as described in more detail

in Answer to Question 5 above.

e. Congress and the Administration should work together to ensure that an ap- propriate system is put in place to provide certainly and timeliness in the permitting process without waiving substantive environmental standards. f. Statutory appointment of an in-situ oil shale permitting focal point to expedite all state and federal NEPA compliance and permitting efforts should be considered. Such a position should have adequate authority and resource to streamline the process and avoid frivolous delays without waiving substantive environmental standards.

g. Congress should identify appropriate tax incentives to encourage investment in oil shale technology and development, similar to those now or previously provided for other non-conventional resources, such as the percentage depletion allowance and Section 29 production tax credits.

7. From an industry perspective, what would you suggest that the Government can and should do to convince industry that Government is willing to be a long-term,

reliable partner in mitigating the risks of establishing a new industry in oil shale?

ANSWER: A good first step has been the Government’s recognition of the oppor- tunity and its subsequent offering of the R&D leasing program by the BLM. Industry will respond to governmental efforts to facilitate and reward pioneers that have

taken the R&D risk and incurred the risk capital to provide new technology, provided that the oil shale R&D technology is conducted in an environmentally responsible and economically feasible manner. Industry will need the U.S. Government to

facilitate a timely regulatory and permitting process to avoid undue obstacles to

project approvals that can and will undermine the economic viability of capital intensive, first-of-its-kind projects, and that royalties generated are properly allocated

to the benefit of those impacted most by oil shale development. In addition, the potential role of the Department of Defense should not be overlooked. As the single largest user of transportation fuels and a key branch of Government with responsibilities for domestic security, the potential availability of an

additional domestic source of clean transportation fuels would seem to be a good fit

as the DOD moves toward its single battlefield fuel of the future strategy in the

next decade. Thus appropriately structured commercial transactions may be an attractive win-win option for both industry and DOD.

8. Do you agree with the perspective that we will need both in-situ and surface processing facilities to make optimal use of domestic oil shale resources?

ANSWER: Although Shell has chosen to pursue exclusively the in situ develop- ment route, we believe that different recovery processes ultimately may be appropriate for different depths, thicknesses, and qualities of oil shale resources; thus different aspects of the oil shale industry will likely involve both forms of recovery.

The financial strength of operators will be also be a major factor, as few companies

can garner the capital resources needed to develop a large-scale oil shale operation.

9. If government were to assist at the R and D phase where do you see the need and

role of government-supported research and development?

ANSWER: In addition to the vitally important aspect of providing small sites

upon which to conduct R&D testing (through the recently announced R&D leasing

program by BLM), there is also an important role for the Government laboratories

in joint research on a variety of technical, engineering and environmental matters

(such as carbon sequestration).

10. You are out in front of this in Colorado, and have an industry perspective on

the planning and impact mitigation process. How should government manage requirements for front-end costs to assure that adequate and timely revenues are

available to communities and are fair and attractive to industry at the same

time?

ANSWER: This is an insightful question that Shell has also been considering to

avoid/mitigate the various types and extents of social and community impacts that

occurred in Colorado in the late 1970s and early 1980s. A large-scale commercial

oil shale operation will have a significant impact on any nearby communities, the

extent of which depends on the existing infrastructures and many other factors.

Such development will require prudent social investments on the part of the operator, as well as the local, state and Federal governments to provide community development resources, which will be defrayed by severance tax and royalty generation. The extent of these needs will be identified in the Social Impact Assessment

process, stakeholder engagement sessions, and other forums of public input, and it

30

will be important for the governments, communities and industry to work together

to provide a sustainable development process.

Mr. GIBBONS. Thank you very much, Mr. O’Connor. We appreciate your presence here today and your testimony is very helpful

to us.

We turn now to Mr. Greg Stringham, Vice President, Markets

and Fiscal Policy, from the Canadian Association of Petroleum Producers. And Mr. Stringham, I notice that you have Mr. Murray

Smith back in the audience. I’m very much aware of Mr. Smith’s

history, his background in Canadian efforts there.

We do know that Alberta is now one of the major producers of

oil for the United States, from its oil sand. So if you would like to

have Mr. Smith join you at the table, please let me invite Mr.

Smith up to join you for your testimony.

Mr. STRINGHAM. Thank you. That would be great. I will have Mr.

Smith speak just following my comments, if that’s OK with you.

Mr. GIBBONS. Absolutely. Please.

Mr. STRINGHAM. Thank you, Mr. Chairman.

Mr. GIBBONS. The floor is yours. We look forward to your testimony.

STATEMENT OF GREG STRINGHAM, VICE PRESIDENT,

MARKETS AND FISCAL POLICY, CANADIAN ASSOCIATION OF

PETROLEUM PRODUCERS

Mr. STRINGHAM. Thank you. It’s a pleasure for us to appear before you, Mr. Chairman, and Committee members. It’s not very

often that Canada takes the opportunity to be able to appear before

these committees; but we thought that today, given our experience

in oil sands, recognizing it is somewhat different than the oil shales

and tar sands that you have in the United States, it would be useful for us to be able to share our experience with you, to be able

to see if there are some learnings there that may be useful.

As you mentioned, Mr. Chairman, the oil sands that we have in

Canada are in full development. It was unconventional at one point

in time. And as you said in your opening remarks, it is not unconventional any more. It is certainly being produced at a rate of 1

million barrels per day, coming out of the oil sands. And from

Canada, that represents one out of every two barrels of oil that we

produce. And as you know, we export well over half of our production to the United States at this point in time. So it is a very valuable resource.

We look forward, as the projects have been announced, to having

close to 3 million barrels a day coming out of the oil sands in just

ten years time. So there is a very strong growth that’s happening

in the oil sands, and that will then mean that three out of every

four barrels of oil produced in Canada will be coming from the

heavy oil and oil sands resource. So it has now become a very conventional and a very important resource.

It does also have in there—and we will use a number of numbers—but 174 billion barrels of established reserves. You mentioned in your opening comments the 1.7 trillion barrels in place,

but we know that we can get at, with today’s technology and economics, over 174 billion barrels. Now, that’s a big number. To put

31

it in context, that’s well over 200 years’ worth of production at today’s levels of projected production going forward. Very large number.

One of the things that I learned as a young engineer coming out

of university, I began working in research in the oil sands, and

that was over 20 years ago, and there were already a handful of

commercial projects underway. This is not a short-term research

project that will provide instant results.

But what has happened in Canada is there has been a long-term

effort of research and development and incremental improvements

over time, similar to the projects you’ve heard from these other

gentlemen, that have unlocked the key to the development of this

key resource in Canada.

One of the things that was really critical was the reduction in

cost estimates. And in the information that I have provided to you,

the supply costs for the development of the oil sands in Canada for

the heavy oil, which is very much—bitumen is the name of it. It’s

tar-like. You have a sample of it, I think, you’ve seen; almost molasses-like material. The cost of development, including capital

costs, operating costs, royalties, taxes, and the return to the investor, is somewhere in the range of $8 to $15 a barrel U.S.

If you upgrade it into the light sweet crude, which has no bottoms and then can fit right into a refinery very, very nicely, the

cost of that is somewhere in the range of $18 to $23 a barrel—all

in supply costs; not just operating costs. So you can see that it becomes very economic to develop this resource.

I would like to point out the key differences that we see between

the oil sands in Canada and the tar sands or oil shale. As you may

or may not know, the oil sands in Canada has been blessed by its

formation with a water layer that surrounds it. So you have a sand

molecule that’s surrounded by a water layer; and then the oil, or

the heavy oil, sits on the outside of that.

And so the separate process is somewhat different, and perhaps

a little easier, than the oil shale. It’s a lot like salad dressing. If

you shake it up and mix it with water, the oil will float to the top,

the sand to the bottom, and the water stay in the middle. And

that’s essentially the process. It can be done at about 60 to 70 degrees Fahrenheit, and doesn’t require the extensive energy that’s

used in other processes. Whereas the oil shales and tar sands, as

I understand that you have in the U.S., has the sand molecule with

oil just locked right on top of it, and requires these additional

processes.

One of the things that I could pass on as one of the key elements

of success that we have seen in Canada in the development of the

oil sands has been a very strong cooperative relationship between

industry and government on the research. And I’m not now just

talking bench-scale and lab-scale research. What was a really key

unlocking feature that happened early on, and again back in the

1990s, was cooperation between the government and a variety—a

consortium of industry players, that developed technology that,

when it then became successful, was immediately dispersed

throughout the industry, because everyone had access to it. So

there’s a two-pronged approach: the consortia, dispersion of

32

technology; as well as the individual projects like Shell and OilTech and others that are doing right now. To give you an idea of investment that’s being put into this, at a commercial level now, we are investing this year $7 billion into

the oil sands in Canada. Over the next five years alone, we will invest another $36 billion U.S. in the development of these projects.

And these projects will then, as I said, turn around and produce

close to 3 million barrels a day over that ten- to 12-year period. I’ve brought with me today a summary that’s put together by our National Energy Board, your equivalent to the FERC here in the

United States. They have done a historical, technological, research,

and market analysis of the oil sands in Canada that gives you an

outline of the technologies used, how the research was developed.

And I will leave that here with the clerk for your information. I

won’t go into the detail here. But it is a very good summary document to provide the background for you. And last, I must mention that as we look forward in the oil sands

development in Canada, we do recognize that the United States is

a key and our primary market—a very good customer. The reason

that we are here today is because we would like to share that experience, learn mutually; but also, to get you to recognize that as we

develop this new oil sand, it will require new markets, including

new changes to refineries, modifications and building of refineries,

to be able to handle the oil that we expect to come out of Canada,

as it moves into the growing market of North America. Thank you very much. Let me turn some time over to Mr. Smith, if that’s OK, Mr. Chairman.

[The prepared statement of Mr. Stringham follows:]

Statement of Greg Stringham, Vice President, Markets & Fiscal Policy, Canadian Association of Petroleum Producers

Overview of Canadian oil sands development and technology

The Canadian Association of Petroleum Producers appreciates the opportunity to

submit this overview of the Canadian experience in oil sands development to the

House Energy and Mineral Resources sub-committee.

While the issue that this committee is addressing has multiple aspects with much

more detail than provided here, CAPP believes that many of the experiences, technologies, policies and research processes used in Canada to develop its oil sands

resources would be beneficial to the committee on this subject.

The oil sands in Canada are a vast resource. From early discovery and use in the

1800’s to first commercial production attempts in the early 1900’s, and government

directed pilot tests in the 1920’s and again post WWII, they moved into early commercial production with the Great Canadian Oil Sands (now Suncor) in 1967. Technology has been the key to unlocking this resource and production now exceeds 1

million barrels per day. Forecasts see this growing rapidly to over 2.7 million barrels per day in the next 10 years.

While oil sands are significantly different from oil shale the government and industry research and development process could provide valuable and potentially

transferable insights for oil shales.

The main difference between oil sands and oil shale is that the oil sands are particles of sand, surrounded by a microscopic layer of water that is then in turn surrounded by the heavy bitumen (thick oil), as shown in the diagram at the end of

this submission. Separating the oil from the oil sands is much easier because of this

water layer, since the oil is ‘‘suspended’’ in the water/sand layer not directly stuck

on the sand.

In oil shales, this layer of water is not there and the oil is stuck directly onto

the rock making it much more difficult to separate the oil from the rock (shale).

The key to unlocking the vast potential of the Alberta oil sands has been sustained and cooperative industry and government research and development. This includes research efforts under the Alberta Research Council, the Alberta Oil Sands

33

Technology and Research Authority, the Canadian Oilsands Network for Research

and Development and more recently the Alberta Chamber of Resources’ Oil Sands

Technology Roadmap and the research coordination of the Alberta Energy Research

Institute.

The attached set of charts and pictures outlines the oil sands resource in Canada,

the history and the technologies that have been key to unlocking this vast resource.

The real key to the development has been a long and dedicated research and development program that has yielded technologies and advancements that have reduced

costs and provided economic access to the oil contained in this resource.

In addition Canada’s federal regulatory agency, the National Energy Board

(NEB), has published two Energy Market Assessment reports on Canada’s oil sands

that provide detailed information on the Canada’s oil sands resource, technology, research, supply costs, production, pipelines and markets. They are available from the

NEB at www.neb.gc.ca under Publications, Oil Sands

CAPP would be pleased to respond to any questions the committee may have regarding the Canadian oil sands and we would be pleased to do this either in writing

or when we will be in Washington at the end of June 2005. Please direct any questions to:

NOTE: Attachments to Mr. Stringham’s statement have been retained in the

Committee’s official files.

Response to questions submitted for the record by Greg L. Stringham, Vice

President, Markets & Fiscal Policy, Canadian Association of Petroleum

Producers

Question 1: Alberta’s oil sands production is often likened to U.S. oil shale production potential. The similarities with U.S. oil shale cannot be dismissed. Please tell

us how your industry engaged and cooperated with the various government and

private citizen stakeholders to create the mammoth producing capability you have

today.

The key to unlocking the vast potential of the Alberta oil sands has been sustained and cooperative industry and government research and development. This includes research efforts under the Alberta Research Council, the Alberta Oil Sands

Technology and Research Authority, the Canadian Oilsands Network for Research

and Development and more recently the Alberta Chamber of Resources’ Oil Sands

Technology Roadmap and the research coordination of the Alberta Energy Research

Institute.

Stakeholder consultation and input is sought out. There is an extensive pre-application consultation process for sharing information as well as raising and addressing stakeholder concerns. In addition the regulatory process addresses the technical,

environment and socio-economic aspects of these projects and provides an avenue

for affected stakeholder issues to be addressed.

In Canadian oil sands development, there is a balance of roles between government and industry. The resource is owned by the province, which leases the

resource to industry to develop and in return receive a royalty payment (described

below). In addition, governments provide policy foundation and the public infrastructure necessary to enable the developments and the private sector provides the

investment and expertise to construct, operate and reclaim the project. This

combination results in environmentally sensitive development, job and business

creation, royalty and tax revenues to governments and earnings to the private

investors.

Question 2: What problems does your industry face as it continues its exponential

growth?

The Canadian oil sands are set to increase from its current 1 million barrel per

day level to 2.7 million barrels per day in the next 10 years. This is one of the only

areas in the world with the potential to increase production on this scale. But it

is not instantaneous nor without challenges. While the historical challenges of technology and economics have been overcome, we are still working on new technologies

and continuing to lower costs. The main issues of this rapid growth that we are now

facing are:

• Ensuring adequate infrastructure—roads, housing, municipal services

• Ensuring an adequate workforce—we are already starting to see shortages of

skilled trades, technicians and professional employees

• Access to markets—with the growing oil production, new pipelines will be

needed to access new and existing markets. We will also need new refineries

or expansions to accommodate this growing supply.

34

Industry is working closely with governments, labor organizations and other in- dustries to address the labor challenges. Industry is also working with several pipeline companies, refiners to address market access and growth.

Question 3: We heard your lessons about early royalty relief and expensible deprecia- tion for oil sands plants that require high front-end capital investments. But there

were additional hurdles to first-generation investment that Canada succeeded in

crossing prior, with great perseverance. What fiscal and programmatic steps

should the United States take to get past the hurdle of establishing a first-generation oil shale facility in the United States?

There are several aspects to encouraging first generation technologies in the oil sands. While they may not apply directly to the oil shale and tar sands in the US,

the Canadian experience may provide ideas for how the concepts were applied for

oil sands in Canada and could be used in the U.S. or modified to apply more specifically to the oil shale and tar sands. In Canada, the successful fiscal and program steps included:

• Joint government and industry funding research and development—over many

years starting first with government research labs and extending to pilot scale

demonstration projects with multiple companies. This was more than a single

program. It was multifaceted and wide ranging. It included government labs

and research facilities, universities and industry pilot and demonstration

projects. • The fiscal (royalty and tax) regime was critical. While it started out as a caseby-case negotiation, it quickly became evident that the provincial royalty regimes for conventional oil and gas would not work. The high front end capital

costs and the long lead time investment before production began were two

unique challenges that led to a two tiered royalty regime. The first tier was a

relatively low front end royalty based on production (ranging from 5% in the

early years down to its current 1%). This royalty is in place until the project

reaches ‘‘payout’’ where the revenues generated equal the costs invested. At

payout, the royalty rate then increases to 25% of net profits (revenues minus

costs). Regardless of the details, this two tier royalty regime was effective for

helping developers cope with large upfront capital cost risks of these projects.

• From an income tax perspective, in 1996, the federal government allowed oil

sands to be treated like other mining operations for tax depreciation. This allowed the upfront costs to be deducted up to the level of income from the project

and made the tax treatment similar to exploration expenses for conventional oil.

35

Question 4: In the end, all development depends on a willing investor to invest

capital. What are the risks to investing capital that might be at least partially

mitigated by Government policy and legislation?

As mentioned previously, the largest initial risks in oil sands were technology and

economics. While we believe that the market is the best determinant of project economics, government policy and legislation can both set a foundation of certainty and

stability that can encourage the early ‘‘pre-commercial’’ stages of any resource development and ultimately enable commercial developments. The benefits of unlocking

this development have broad public application from employment, tax base, innovation and business and economic development. In addition to technology, governments can focus on policies and legislation regarding tax and fiscal regimes, timely

regulatory approvals, land management and provision of infrastructure such as

roads and services that enable these developments to proceed.

Question 5: What regulatory issues should we anticipate as placing unacceptable

timelines on investment payout, and how has Canada handled these?

With the large upfront capital investment for oil sands projects, the longer the

time between the initial investment and when oil production begin; the higher the

capital risk and the more negative the impact on the economics. The regulatory

process is a major determinant of the time it takes from application to production.

In Canada, the growing complexity of the regulatory process and the duplication of

requirements from different levels of government are creating a longer process.

Industry is working with governments and regulatory agencies to make the regulatory process more efficient. To be clear, this does not lower the regulatory or environmental standards to be met, but is simply trying to use single window approaches or find ways to meet the needs of multiple regulators with a single application.

The recent application by Imperial Oil for the Kearl Oil Sands Project is a good

example of the timelines associated with these large oil sands projects and the need

for an efficient regulatory process. As can be seen on the timetable shown below,

even with an assumed two year regulatory process, it will be a seven year process.

Pre-application work began in 2003 and first oil production isn’t expected until mid2009.

The Alberta Energy and Utilities Board has prepared a document titled Guidelines Respecting an Application for a Commercial Crude Bitumen Recovery and Upgrading Project that outlines the regulatory expectations for preparing an application for these projects that may be useful reference to your committee. It contains

following sections:

1. General Information

2. Technical Information

3. Economic Information

4. Environmental Impact Assessment

5. Biophysical Impact Assessment

6. Social Impact Assessment

7. Environmental Protection Plan

8. Conceptual Development and Reclamation Plan

9. Solid Waste Management

The complete Guideline document is available on the Board’s website at: http://

www.eub.gov.ab.ca/bbs/products/guides/g23.pdf

36

Mr. GIBBONS. Absolutely. And Mr. Smith, we appreciate the fact

that you have been able to come and join us today. We understand,

of course, your historical background as the former Minister of

Energy for the Canadian Government. We would hope that you

would be able to address maybe the idea of: How do we cooperate,

how do we get governments to work together to produce and make

this issue of unconventional oil resources a conventional oil

resource for America? Thank you.

STATEMENT OF MURRAY SMITH,

FORMER MINISTER OF ENERGY, CANADA

Mr. SMITH. Well, thank you very much, Mr. Chairman. It’s a

privilege for me to appear in front of the Committee. And I have

been assigned to Washington to represent Alberta’s interests here.

And I must thank you, this Committee, and other committees, for

the gracious welcome I have received. It’s actually good to be in

Washington—and you don’t have to buy a dog to have a friend.

I want to comment just briefly on the role that government can

play. We knew we had this outstanding commercial resource available. But you couldn’t think of it as an oil resource; we had to

think of it a mining resource. And in fact, because it is now truckand-shovel, it is a mining process. We adjusted a royalty scale to

attract investment.

And the royalty structure works in such a way that we charge

1 percent of all production revenues until the project—each defined, specific project—reaches a point of pay-out. After it reaches

pay-out, the royalty structure then reverts to 25 percent of net royalties; which then is an appropriate economic rent for the people

of Alberta, who own the resource. This is all taking place on federally owned—or what we would call ‘‘crown lands.’’

Transparent economic rents are a critical factor in developing

this resource. We did not have to put any money, per se, toward

an oil company, in terms of a direct incentive. But we recognized

that with the potential and with the level of investment that they

would make, that we would have to provide something that is both

attractive to get that money in place, the first place; second, to develop the resource at an economical rate; and third, to have a degree of certainty that would last through the period of the resource

development and extraction.

That, combined with over 20 years of shared research and about

a billion dollars—Canadian dollars—worth of research and shared

technology, as Mr. Stringham was pointing out, helped us come to

the point where today we produce this mining resource at an economical rate, where it is delivering over a million barrels a day, on

schedule; to double within five to seven years; and then to go to

3 million barrels a day before the end of the next decade. So the

resource is substantial. It is commercial. It has developed new technologies.

We are also moving toward new technologies that will drop the

operating costs even further, and that is using either the bitumen

itself, or other processes, to substitute natural gas as a fuel. So we

see our operating costs, which now range anywhere from $12 to

$15 U.S., to drop by as much as 40 percent in the future.

37

So once you get a foundation, you can then continue to amortize

your expertise, your technology, and your skills, over a long period

of time. And we think the oil sands will successfully supply crude

oil to this market, to the United States, for the next foreseeable future.

Mr. GIBBONS. Thank you very much, Mr. Smith. We will turn

now to questions and answers for our panelists today. And I think

what I am going to do is withhold my questions until the very last.

I will turn to members of the Committee in order of their appearance here today.

I believe Mrs. Drake was the first on our side. Mrs. Drake, do

you have any questions?

Mrs. DRAKE. Mr. Pearce was here first.

Mr. GIBBONS. Oh, Mr. Pearce. Mr. Pearce.

Mr. PEARCE. Thank you, Mr. Chairman. Mr. Godec, did you have

a chance to look at the report by Mr. Savage, that actually there’s

not any oil in the shale, but it’s in fact organic compounds that are

compressed and made into oil?

Mr. GODEC. No, I did not.

Mr. PEARCE. Do you agree with that assessment?

Mr. GODEC. I am not an expert on oil shale.

Mr. PEARCE. Mr. Savage, tell me about the organic compounds

that they find, and how they are converted into oil.

Mr. SAVAGE. What we do with oil shale is what ‘‘mother nature’’

would do if we had a couple of hundred million years to wait on

her. There is not one drop of oil in oil shale; there’s organic material. And we take that organic material in the form of rock; we heat

it; and under intense heat, the organic material escapes in vapor

form. We capture that vapor, and condense it into liquid. And this

is what ‘‘mother nature’’ would do with the heat and the pressure

of the Earth.

Mr. PEARCE. Are those organic materials available anywhere else

in nature?

Mr. SAVAGE. Well, it’s algae; it’s fish life, plant life. This area

that we refer to as the Green River oil shale deposit was covered

by a lake at one time. When that lake receded——

Mr. PEARCE. What is the magic of these? They are kind of expensive to extract from rock or shale, so why don’t we just gather them

out of nature in easy to gather places?

Mr. SAVAGE. Well, I don’t know why we don’t do that, but I’m

sure that a large deposit——

Mr. PEARCE. I mean, you understand what I am saying? If we

are able to compress these things and just get oil from them, my

question is, why go after them in the very expensive setting that

they are in? Why not just figure out where they are cheaper to get

at?

Mr. SAVAGE. Well, it is not that expensive any more to go after

the reserve that we refer to.

Mr. PEARCE. So you can do it at the $20 level?

Mr. SAVAGE. Absolutely.

Mr. PEARCE. Do you have $15 oil?

Mr. SAVAGE. Yes.

Mr. PEARCE. How much are you producing?

38

Mr. SAVAGE. Well, we’re producing 24 barrels a day with our current retort. And we do not run continuously; reason being is we are

using previously mined oil shale which is owned by the BLM. We

purchase from them. We do not have a mine open, so we’re not into

a commercial venture at this point. But we have run sufficiently

long to have our costs validated. They range anywhere from $9.60

a barrel, to $22 a barrel. That variance is all mining related.

Mr. PEARCE. I understand, but my idea is if you are making

money at, you said, $15 oil, and the price is 60, that is about 45

bucks net profit. I don’t understand why you are not producing millions of barrels, because your profit increases as you generate more

volume. I don’t understand why we’re producing 24 barrels instead

of 24 million barrels; because you know that we need the energy.

Tell me about the economics that keep you from doing that.

Mr. SAVAGE. Well, the difference is that we are a startup company, just having completed the research and development phase,

and just beginning to move into a commercial mode which will consist of opening a mine and building out a series of 1,000-barrel-perday retorts.

Mr. PEARCE. Mr. O’Connor, are you all——

Mr. SAVAGE. We want to do exactly what you’re referring to.

Mr. PEARCE. OK. Mr. O’Connor, are you at Shell pretty involved

in the extraction of shale organic materials and converting them?

Mr. O’CONNOR. Well, yes, we’ve been involved in this for almost

a quarter of a century now. And I generally agree with what Mr.

Savage just said; in that these oil shales are very immature product, and that they don’t flow on their own. The oil and the gas is

chemically embedded in the rock. Through time, heat, and pressure

of tens—maybe hundreds—of millions of years, through this geologic time period, we would see these mature into a more conventional oil and gas field. But in the meantime, they are not freeflowing.

With regard to your questions on the economics, we think that

there are some resources in the Green River Basin that can allow

us to make money in a $25 to $30 oil price world. Now, the question is, why are we not doing that now? Why are we not now today

producing extraordinarily large quantities of oil and gas?

First of all, this is extraordinarily difficult science and engineering and chemistry. We have a tremendous amount that we have

learned, but we still have much learning to do. As just one example, we’re inserting these heaters down into the resource.

Mr. PEARCE. Yes, I read that in your testimony.

Mr. O’CONNOR. Yes. Some of this resource is 1,000-foot deep to

the top of the resource, and 1,000-foot thick below that. So we

would literally be dropping down 2,000 feet of cables or pipe and

heating the bottom thousand feet of that. We’ve had a very difficult

challenge in terms of developing a reliable heater that will last the

many years that are necessary, as the rock heats up and we get

the rock’s chemistry as it is.

Mr. PEARCE. OK, thank you.

Mr. O’CONNOR. In addition to that, while the big technological

challenges are on the sub-surface, the big costs are on the surface,

as we bring it to the surface and then have to engage in the surface

39

processing, the transportation, the power generation, and the other

enormous tasks that would be involved from a practical standpoint.

Mr. PEARCE. I thank you very much for those comments. Mr.

Chairman, my time has elapsed. Thank you.

Mr. GIBBONS. Thank you very much, Mr. Pearce. With the concurrence of Mr. Grijalva, as a matter of personal privilege, we are

going to turn to Mr. Cannon for his remarks before he has to leave.

STATEMENT OF THE HON. CHRIS CANNON, A

REPRESENTATIVE IN CONGRESS FROM THE STATE OF UTAH

Mr. CANNON. Thank you, Mr. Chairman. In particular, thank you

for holding this hearing. This is remarkably important. I appreciate

it. And I’d ask unanimous consent to submit an opening statement

for the record, or unanimous consent that anyone may submit an

opening statement for the record.

Mr. GIBBONS. Without objection, any Member wishing to submit

a written opening statement may do so.

Mr. CANNON. You know, we have some people here today who

are dear friends. And I am not going to take five minutes; I just

wanted to thank Mr. Savage for being here. And you know that we

have these plaques with the material. That is remarkably nice. I

appreciate that. And as I was walking over here, I was explaining

to staff something about this and then, lo and behold, there we

have the material to show them.

And Mr. O’Connor has been a good friend for a very long time.

And we appreciate the work that you have been doing there. Mr.

O’Connor, the world needs this. And as you pointed out, there are

several resources around the world that are similar, that may free

mankind from the burden of not having low-cost energy for the

long term.

I would also like to thank Commissioner McKee for being here.

He is struggling with these issues on the local level. And I apologize that I am not going to be able to be here to hear his testimony.

But I just wanted to thank you all for being here. This is incredibly, remarkably important, as you look at the pressures that are

on the world today. I mean, I thought that $2 gas would be really

a horrible thing; but actually a lot of nice things have come out of

it, including the fact that we may be looking at some of these alternatives in Canada, in shale and in tar sands.

And so Mr. Chairman, again, I thank you for holding this hearing, and yield back.

[The prepared statement of Mr. Cannon follows:]

Statement of The Honorable Chris Cannon, a Representative in Congress

from the State of Utah

Thank you Mr. Chairman for holding this important hearing on Oil Shale, Oil

Sands, and Heavy Oils. As the price of oil is projected to continue to escalate, our

need to depend less on foreign sources is even more apparent. American consumers

have increased their demand for oil by 12 percent in the last decade, but oil production has grown by less than one half of one percent. We import 56 percent of our

oil today, and it’s projected to be 68 percent within 20 years. Fortunately, a solution

is available.

Of the estimated 2.7 trillion barrels of oil held in the world’s oil shale deposits,

2 trillion is scattered across the United States. That’s more oil than all the countries

in the Middle East combined.

40

In fact, the U.S. Department of Energy estimates that the United States is the richest and most geographically concentrated oil shale and tar sands resource in the

world.

This gigantic resource of oil shale and tar sands is well known by geologists and energy experts, but it has not been counted among our nation’s oil reserve because

it is not yet being developed commercially. Companies have been waiting for the federal government to recognize publicly the existence of this resource as a potential

reserve and to allow industry access to it. Oil shale could allow the U.S. to become the world’s single biggest oil source, ahead of all the OPEC members. The Department of Energy’s Office of Naval Petroleum and Oil Shale Reserves estimates oil shale’s direct economic value to the nation might approach $1 trillion by 2020, not counting other equally or more valuable

strategic and national security benefits that may not be fully measured in dollars. Today’s hearing will help us to understand the potential of domestic oil to supply America’s oil demand. I thank the witnesses for being here today and I look forward

to hearing their testimony.

[The statement submitted for the record by Mrs. Cubin follows:]

Statement of The Honorable Barbara Cubin, a Representative in Congress from the State of Wyoming

Mr. Chairman, for three decades, this country has been on the path toward a seri- ous energy supply shortage and an ever growing dependency on foreign oil. Transportation costs are skyrocketing; everything that rolls, floats, or flies costs more to

operate. Add in global energy demand that continues to increase exponentially, and

it becomes very clear that our nation is on the brink of an energy crisis.

Fortunately, adequate energy deposits exist within and just off the coast of our

borders to meet this growing demand. Technology is improving everyday in how to

best access these energy sources, as well as creating new renewable energy supplies.

Western oil shale deposits, including those that reside in the Green River and

Washakie basins in Wyoming, have the potential to play a significant role in an

energy supply solution.

Through passage of the Energy Policy Act, the U.S. House of Representatives has

taken an important first step toward the development of this potential resource by

directing the Secretary of the Interior to develop an oil shale leasing program for

the nearly 2 trillion barrels of oil shale resources located in the United States.

I look forward to hearing from our panel today what investments private industry

is making to ensure the efficient development of oil shale resources in the future,

as well as what economic benefits it would bring to local, state and federal economies.

Thank you Mr. Chairman for holding this important hearing and I yield back the

balance of my time.

Mr. GIBBONS. Thank you very much. Turn now to Mr. Grijalva.

Thanks for your patience.

Mr. GRIJALVA. Thank you, Mr. Chairman. Let me begin, I guess,

directing to Mr. Savage and Mr. Godec the same question. Thinking ahead, and thinking of consequences as we go forward with, as

Mr. Cannon said, this very important research and development

process that we are in.

Although apparently based on some new innovations, it is my understanding your approaches to oil shale production still involve

major mining operations. And if I am correct in that understanding, I just ask the general question: What specific techniques

and precautions will you use to protect surface water, ground

water, from depletion or contamination, to protect top soil stability,

and to control the air pollution from the mining and whatever

other stages of operation? Those are precautionary questions that

I think will have to be asked as we go along with this discussion.

Mr. SAVAGE. Thank you. Our process is a two-step process. One

is the mining. And as Terry indicated, we have to bring the rock

41

to the source of the heat, so it’s mining, bringing the rock out of

the ground. And then the second phase is processing that rock on

the surface.

I can tell you that the retort, or the surface processing aspect,

is fully self-contained. It’s a sealed unit. It’s oxygen-free. In fact, if

we allowed oxygen to get inside of our retort, we would have an

explosion. We would combust the shale. So it’s oxygen-free, sealed

under vacuum. There are no gases or emissions of any type that

reach the atmosphere. The only non-condensable gas that we

produce in this process is propane. And we capture that and, after

processing it, that can also be a marketable product.

The mining aspect of this, relative to the environmental consideration, we apply with the State of Utah in the—we have 39,000

acres of oil shale ground under lease, which is owned by the State

of Utah. We have applied for a mining permit. And they put us

through the hoops and make us dot the ‘‘i’s’’ and cross the ‘‘t’s’’ as

it relates to environmental impact. So we have geological studies

conducted, paleontology studies conducted, archaeological studies,

as well as the reports on our system relative to air and water control and so forth, where we disperse spent shale. And all of that

is contained within the mining plan that the State of Utah will rule

upon.

We are doing nothing more than what coal mining does to the

environment. We go underground and we remove rock and we

bring it to the surface. And you asked about methodology.

Mr. GRIJALVA. That is an interesting point. I think that there is

an estimate that there is a $26 billion price tag on reclaiming coal

mines across this country. And that is kind of the precaution and

anticipation in unintended consequences that I think need to be

looked at, as well.

Mr. SAVAGE. One of the things that I might mention is, in this

area where we are currently operating there are mined out and

abandoned gilsonite veins. Now, you wouldn’t want to walk around

in this area in the dark. We’re talking about 50-foot-wide veins

that maybe go 1,000 feet deep, and they go for miles across the surface of the Earth. The State of Utah has asked us to take the spent

shale and begin filling in these cavernous areas.

Mr. GRIJALVA. Thank you, Mr. Savage, and thank you for the visual. Appreciate it very much. And I had asked the question of Mr.

Godec, as well, but for the sake of time, let me begin with him on

the second question to both the same gentlemen. With your anticipated ability to produce fuel from oil shale at such a low price, can

we correctly assume or expect that you will be able to operate without any government subsidies or tax breaks?

Mr. GODEC. Is this directed to me, or to Mr. O’Connor?

Mr. GRIJALVA. We will begin with you this time, because I cut

you off on the other one.

Mr. GODEC. No, I was really not referring or speaking to oil

shale. And so I’m really not qualified, I don’t think, to talk about

the economics of oil shale production.

Mr. GRIJALVA. Mr. Savage? Mr. O’Connor?

Mr. SAVAGE. Well, we have never asked for, neither are we asking now for government subsidies. I think the position that Canada

has taken would amply suffice for our needs, in some sort of

42

royalty breaks when working upon Federal ground, and maybe

some tax investment credits, those kinds of things.

Mr. GRIJALVA. And if I could direct a question to Mr. O’Connor,

well, the same question about the process is relatively low market

in terms of cost and prices. Am I correct in assuming that that can

be done without subsidies or tax breaks? Same question.

Mr. O’CONNOR. Shell has been at this for almost a quarter of a

century, and we’ve done it all on our own land. We’ve done it all

without any government involvement or subsidies whatsoever.

We’re not seeking any money from the Federal Government going

forward; despite the fact that a large-scale commercial operation

will be very substantial in its capital expenditures.

As my testimony does indicate, though, we think that there are

areas where clarification and some parameters need to be set

around the issues of Federal royalties; since the Federal Government owns somewhere between 72 and 80 percent of all the oilshale-bearing lands in the basin. And also, there are some issues

involving tax credits, where they are or in the past have been

available for a variety of other type of non-conventional fuels. And

to the extent that it becomes appropriate to have discussions to

seek clarification on which of those should be considered in the future, we think that oil shale should be part of those discussions.

Mr. GRIJALVA. If I may, the last question, Mr. Chairman, Mr.

O’Connor, you mentioned BLM’s new experimental leases. Do you

anticipate, or do you think Shell will seek one or more of these

leases in the near future?

Mr. O’CONNOR. Shell, in fact, has applied for an R&D lease on

Federal lands. You’ve raised an interesting question, that I’m so

glad that you asked about one or more. My testimony in the written form indicates that there is an 85-year-old provision in the

Mineral Leasing Act of 1920 that restricts companies or individuals

from acquiring more than one oil shale lease anywhere in the

United States. It’s ironic that that still exists.

That provision and that restriction was created for all the other

commodities, too: oil, gas, coal, phosphate, and all the other

leasable minerals. And with the exception of oil shale, those restrictions have all been modified throughout the years.

So we think it is extraordinarily important for Congress to take

a look at this. Because otherwise, if a company does develop—does

secure a Federal oil and gas lease, and then successfully develops

a project on it, it is then out of business in terms of any further

development on Federal lands.

And we’re not suggesting opening up the flood gates in terms of

unrestricted leasing, but this single-lease limitation really does cry

out for consideration in the 21st century.

Mr. GRIJALVA. Thank you, Mr. Chairman, for the additional time.

Appreciate it.

Mr. GIBBONS. Mrs. Drake.

Mrs. DRAKE. Thank you, Mr. Chairman.

Mr. Savage and Mr. O’Connor, it sounds like you are both doing

this. I wondered what the regulatory process was, and how long it

took you to be able to get your permitting to be able to do what

you are currently doing, and what you think you are looking at—

of course, if you go out on Federal lands, it is going to be another

43

process—what the timeframe is going to be for you to do what you

would like to see happen. What it took you to get to where you are,

and what you anticipate.

Mr. SAVAGE. Well, currently, we have a research and development site which consists of an acre of ground in the middle of several thousand acres that we have under lease with the State of

Utah.

Mrs. DRAKE. OK.

Mr. SAVAGE. And the permitting process for this research and development aspect of the project was not long in coming. We were

able to obtain the necessary permitting within a few weeks time.

The mining permit which we have applied for, we first applied

for that more than 12 months ago. And that’s still in the process

and will come up—as I understand it, within the next couple of

months it will come up for a 30-day public review. And after that

review, we may be asked to give additional information or more detail as to our mining operation plans. And then it will be ruled

upon, and we’ll either be permitted or not. We anticipate being permitted.

Mrs. DRAKE. But you don’t see it as a very long, extensive

process, like we have heard in other committee meetings with other

types of things that are being mined?

Mr. SAVAGE. No. It hasn’t been on the state level. As we look at

the Federal requirements, that could take substantially longer. And

if we would have one request in addition—I think Terry made a

very good point about the Mineral Act—but instead of subsidies, we

would like to see more cooperation of the Federal Government in

trying to move this project forward, through some relaxation, if you

will, of the requirements to get to where we need to be.

Mrs. DRAKE. Mr. O’Connor, did you want to add anything?

Mr. O’CONNOR. Yes, ma’am. Despite the fact that we don’t actually mine any of the resource, because of the peculiarities of the

State of Colorado regulatory regime, we’re regulated as though we

are a mining operation. Having said that, in the past, because of

the very de minimis size and disturbance involved in our five research projects so far, time and complication has not been an overriding factor for us in the permitting process.

But I hasten to add, this has all been done on our own land.

When you overplay the involvement of Federal lands, along with

the larger and more complex size of a commercial operation, we

fully expect that, under the best of circumstances, it’s going to take

us probably five years, at least, to be able to permit our first commercial operation.

Now, I mentioned in our testimony that we’re hoping to make a

final investment decision for a large commercial operation by the

end of this decade. That means that, despite the fact that our technology is yet not proven at commercial scale, although we’re getting

increasingly optimistic, we literally have to start now with gathering environmental data, preparing environmental impact statements, starting down that road, in anticipation of what under the

best of circumstances may very well be at least five—and could be

15 or 20—years of permitting activities.

It is here where we will desperately need government help. And

we’re not here seeking any waiver of environmental standards, or

44

waiver of substantive environmental issues. But the large and

daunting looming of multiple sequential permitting processes, each

of which could be very complicated, each of which could be subject

to lots of controversy for those that don’t want to see any oil shale

development, could extend to the point where what looks like a

very attractive project or projects for us in the future could lose

their luster as the years and the decades could drag out.

Mrs. DRAKE. And Mr. Stringham, I wondered if you could tell us

how the process works in Canada, and the regulation, the timeframe. I did notice that you are also in Saint John’s, Newfoundland. I will actually be visiting there in August.

Mr. STRINGHAM. Oh, congratulations. It’s a great place to visit.

Mrs. DRAKE. Well, it is. My mother lives there. I go quite frequently.

Mr. STRINGHAM. Perfect. Well, then you understand that, as well.

The regulatory process in Canada is not much different. If it is

under provincial control, then certainly you can move more quickly.

But what we have in Canada is we have provincial and Federal

regulation overlapping, very similar to state and Federal here. And

so from that perspective, for a large oil sands plant, certainly it can

take a two- to three-year process.

Mrs. DRAKE. A two- to three-year process?

Mr. STRINGHAM. Two- to three-year process.

Mrs. DRAKE. Not 15 to 20?

Mr. STRINGHAM. Yes, that’s correct. Although, you know, for the

early days, certainly, it took longer than that. But we really tried

to work it down to a two- to three-year process.

Mrs. DRAKE. Thank you very, very much. Thank you, Mr. Chairman.

Mr. GIBBONS. Thank you, Mrs. Drake. Mr. Jindal.

Mr. JINDAL. Thank you, Mr. Chairman, first of all, for calling

this hearing. Given the price of energy in our country, I think this

hearing couldn’t be more timely. And I want to thank the witnesses

for their information, as well.

The first question I’ll direct at Mr. Savage and Mr. O’Connor, but

I invite any of the witnesses, certainly, to respond to this. I am just

curious, as we have heard about the wonderful resources that are

potentially available to us right here in our own country, across

North America, I am wondering, what are the most important

steps we can take in the Federal Government to encourage timely

production of a large volume of oil, not only from oil shale, but from

the oil sands and some of the other resources we have heard about

today, as we think about completing our work on the energy bill?

I am just thinking in concrete terms. What do you see as the three

biggest barriers? And what are the three specific things we could

be doing in Congress to help speed along the development of this

process?

Mr. SAVAGE. Well, I think we’ve mentioned a couple. When we

realize that 80 percent of this ground that we speak of, oil shale

property, is owned by the Federal Government, there has to be

some cooperation from the Federal Government as to the land

usage. The leasing of the land, as has been stated, it’ll be required

that there be more than one lease granted to one company. That’s

a given. Help with companies to meet the environmental impact

45

issues; but to help us, and not stalemate us, in moving those forward on a more quickly [sic] basis, more rapid basis.

Mr. O’CONNOR. Just referring in general terms to our written

testimony, we’ve identified six areas where we think it’s strategically important to have legislative and/or regulatory proactive support from the Federal Government.

The first is more on the policy level; is to really have an official

declaration from the highest levels of this Government, both Legislative and Executive, that oil shale is a strategically important

energy fuel which should be developed on an expedited basis, if it

can be done in an environmentally acceptable and economically feasible manner.

Why is that? Well, very honestly, because of the failures of the

’70s, there is so much misperception, and thus negative overhang,

involving oil shale, that we think that even many of our friends remember the past failures—that largely precipitated from a rapid

decline, an unexpected decline, in oil prices—and are not really

particularly focusing about the advances of technology. And so as

a result, in many cases, we are finding ourselves attempting to try

to push something up a waterfall. And if we can get into a policy

pull position, that can really make a big difference.

Second, encouraging and directing the Interior Department to develop a commercial oil shale program. And as I said, you know,

they have taken a very important initial step, but they need to follow through to develop—they’ve had authority since 1920. And except for four oil shale leases that were issued in the 1970s by Executive Order from the President, no oil shale program, leasing program, has ever been developed. And certainly, the time has come.

And we applaud the Department for taking this first step.

Third, we’ve already mentioned the single-lease limitation, which

can really be a show-stopper for long-term investment and approvals necessary because of the extraordinarily long capital that is

needed.

Fourth, the Secretary has unbridled discretion to set royalties at

whatever rates. And while that doesn’t require specific legislation,

we think that the extraordinary amount of capital at the front end,

and the high-risk capital, and the high technical risks that are involved in first-generation facilities that’ll be the first in their kind

in the world, literally, need recognition that some parameters on

royalties, particularly in the first iteration of royalty setting, be set;

perhaps along the lines of what the Canadians did.

I’ve also represented or mentioned earlier about the permitting

needs where, instead of getting involved in the endless cycle of

multiple sequential permitting that could drag five years into multiples of that, some Legislative and Executive efforts to try to consolidate these into more rational concurrent reviews will make

enormous sense.

And finally, just mentioning that there are some ambiguities in

the tax laws regarding whether or not oil shale would qualify for

some of the same type of tax treatment that other unconventionals

do, also needs to be clarified. Thank you for the question.

Mr. JINDAL. Thank you.

Mr. SAVAGE. May I make one more comment along those lines?

There’s a tract of land in eastern Utah that’s owned by the Federal

46

Government which we refer to as ‘‘UAUB.’’ This is a tract of land,

approximately 10,000 acres, which was leased to the consortium of

Phillips, Sun Oil, and Sohio, back when the commercialization of

oil shale was underway.

They have developed—‘‘they’’ being the consortium developed—

an underground mine which, upon abandoning their project, that

mine was turned back to the care of the BLM. And at one time,

it was attempted to reclaim—the BLM wanted to reclaim that

mine, for many and various reasons. It remains open, although

there has been some signs of closure.

If a company like Oil-Tech, which is ready with a surface retorting process to move forward, if we could lease that ground containing that mine, we could move forward very, very quickly. We

could be producing thousands of barrels of oil a day very quickly.

Mr. GODEC. Just a couple of comments to reiterate, I think, in

kind of applying it across the board to all unconventional oil

resources, not just oil shale, I think there’s a lot that we can learn

from our neighbors to the north in Canada about effectively,

through public/private partnerships, encouraging and facilitating

the development of a resource that’s technically challenging and

unfamiliar to much of the operating community.

And that was done in Canada, and it’s what I’m recommending

in my recommendations to this Committee; to include, you know,

both updating and publicizing the information on the geologic characteristics of the resource, where it is, what its characteristics are;

publicizing current technologies and how those might be applied to

these resources through demonstration projects and field pilots;

taking that best technology today and looking at it to see what else

we can do through research and development and improved science

to improve the recovery; and then providing fiscal incentives to

help basically share the risks between government and industry in

going after these new technologically challenging projects in a way

that both facilitates their development, but in the long run is not

a net subsidy forever for these kinds of resources.

I think you can look at unconventional gas resource development

as a prime example where, here in the United States, through the

combination of research and development and effectively targeting

fiscal incentives, we’ve been able to turn what was once an obscure,

unconventional resource—tight gas and coalbed methane—into a

resource now that provides one-third of our domestic natural gas

supplies.

Mr. JINDAL. I want to thank the witnesses. My time has expired.

I just want to echo two things. One, I want to thank each of you

for your specific recommendations. Mr. O’Connor, I think you said

it best, in that it is incumbent upon us to develop our technologies

in an environmentally sensitive way to take advantage of these

energy resources that are present in our Nation.

And second, even though, Mr. Stringham, I didn’t get a chance

to ask you the question I would have asked, I think we have a lot

to learn from our neighbors to the north. And we certainly appreciate your coming and sharing with us how this regulatory regime

has worked in Canada. Thank you.

Thank you, Mr. Chairman.

47

Mr. GIBBONS. Thank you very much, Mr. Jindal. And in fact, I

want to follow up a little bit with where he left off, and maybe

question Mr. Murray [sic] with regard to the relationship.

Our next panel that is going to come up is going to talk about

the state-county relationship and their involvement, of course, with

this resource. I would ask you a question. The Canadian Government, with regard to the province of Alberta, its local communities,

what was the relationship? And how did they work together with

the stakeholders in this in order to develop these oil sands in

Canada with such an expedited timeframe, if you will?

Mr. SMITH. The original Great Canadian Oil Sands plan started

in 1977. The first barrel out was at $35 U.S. And it seemed at that

time that the path was going to be fairly long. The ownership

structure of the resource is the government of Alberta, the province, owns the resource; and the Federal Government oversees

inter-province or inter-state movement of that product. So the local

ownership did play an important role.

The Federal Government recognized the value of the resource for

all of Canada, and contributed by putting money into a joint research fund, called the Alberta Oil Sands Technical Research Authority. That authority shared technologies with the private sector,

and shared funding with the private sector over a 20-year period,

to the tune of about $800 million.

The companies would invest their money into oil sands development, into oil sands technology, and then would be treated differently through this stage. In 1993, what we did is started to take

each individual lease that was rented by the oil company and give

them certainty so that the period of development they would be

able to keep the lease. Second, they would file an annual mining

plan, an annual review plan, an annual audit plan, with the province of Alberta.

They would be regulated in environmental practices and mining

operations by an arms-length regulatory body called the Alberta

Energy Utilities Board; which today monitors their activities on a

daily basis.

And then, in 1996, we started on what we call the generic royalty

program; which then said, ‘‘One percent of your production revenues, until the project is paid out; then we move to a 25 percent

royalty structure of net revenues.’’ And that really was the kick

start.

And that was combined with a Federal contribution of accelerated depreciation, or accelerated capital cost allowance, where they

could write off in one year what they had spent in the terms of that

year’s investment.

Those factors really contributed to recognizing the front-end-load

risk of capital; and through that, helped us bank a total investment

of some $80 billion now into these oil sands. So it was very much

certainty, very much transparency, and then a working partnership

of shared technologies, that helped stimulate the development.

And those started to move in terms of, if you mine the first 80

feet of oil sands, you can mine it using truck and shovel. However,

to make the deeper deposits economical, we use a process called

steam-assisted gravity draining. And what that is, is we inject

steam into the bitumen and we then heat the rocks up enough to

48

make the bitumen flow into a pipe, and which is then piped away.

Eighty percent of our oil sands resource will be developed through

this system.

That technology was developed and is now shared by more than

one company. And I think that that non-proprietary sense really

accelerated our development. And so each time we leapfrogged in

technology, we were also able to put additional downward pressure

on cost; to the point where we, you know, see this now competing

worldwide on a very favorable basis.

The last thing—and you know, from a conservative government

you sometimes wonder about the wisdom of it at the time—but in

fact, the government of Alberta owned 10 percent of the oil sands,

the initial oil sands development, and was an active equity partner;

and only discharged its equity interest in 1995. But I think that

what we found is that actually holding an equity interest was more

of a hindrance than it was a catalyst. And so by divesting, we then

in fact accelerated the growth and development of the oil sand.

Mr. GIBBONS. Well, Mr. Smith, let me follow up with what you

just told this audience. I think it is very important to note that the

Canadian Government, and the province of Alberta, stuck with this

program back when oil was on the market for less than $20 a

barrel—probably in the $10- to $20-a-barrel range—which says a

great deal about the confidence of the Canadian Government, and

the Alberta government, as well, with approaching this issue. To

get to where you are today of producing 1 million barrels of oil per

day from these oil sands I think gives great credit.

We are pleased that you had the foresight, but also the gravamen, to stick with it, as they say, so that you are now in that position to demonstrate I think to not just the world your ability to

produce, but you are actually demonstrating a marketable product

today that when you began was questionable at $35 a barrel.

I think it is just a remarkable story that you have to tell us, and

we are very glad that you were here to explain that.

Mrs. Drake, do you have any additional questions for this panel?

Mrs. DRAKE. No, thank you, Mr. Chairman.

Mr. GIBBONS. You know, I have several questions for this panel.

But I notice that the time is dragging on. We have kept you gentlemen here for an hour and a half. We have a second panel.

I would like to mention that we would have some written questions to follow up to ask, very important questions about the

process, about the efficiencies. There will be questions about going

forward with technology: how do we share technology; how do we

develop this resource in the short-term future? I think for this

country, for this Nation, working together, developing technologies,

are critical for the development of this resource, to overcome our

dependence on foreign oil.

We as a nation owe it to the people of this country to do what

we can to expedite this energy resource, so that we have the ability

to provide oil for the economy to make it run in this country. So

you gentlemen sitting here today have opened the door to, I think,

a very bright future.

And I think we can safely say that our energy future with regard

to oil and gas has yet to see its brightest days, because of what you

49

are doing in the oil sands, the oil shales, and the heavy oil unconventional market today. So with that, I want to thank each and every one of you all, ex- cuse this panel, and call up our next panel, if I may. The second panel will be Mr. Russell George, Executive Director of the Colorado Department of Natural Resources; and Mr. Michael

J. McKee, Commissioner, Uintah County, Utah. While we are waiting for these gentlemen to approach the witness table, let me submit for the record the testimony of Juan

Antonio Granados, President of Shale Oil Information Center,

Incorporated.

[The statement of Mr. Granados submitted for the record

follows:]

Statement of Juan Antonio Granados, President,

Shale Oil Information Center, Inc.

Liquid Fuels from American Shale and Tar Sands—The Challenge— The Mission

Today, 70 percent of all liquid fuels are used to sustain our efficient transpor- tation system; the envy of the world; our Achilles heel. Damage to it, will destroy

our economic system. What we are talking about here today will take 10 or 15 years

to be fully implemented ‘‘if we start this year, enough time for the enemies of America, in the Middle East and in Venezuela to bring us to our knees. Thereto, our challenge here today. And $150.00 oil, maybe? In 1979 the late Dr. Armand Hammer prophetically wrote ‘‘The escalating price and growing shortage of petroleum are beginning to influence our life styles and employment patterns, and to compromise our standard of living’’. He said this while

promoting the development of our oil shale resource. What happened? This Congress can elect to take the high and responsible road to promote the full and reasonable development of the Colorado/ Utah/ Wyoming oil Shale and tar

sands resource as soon as possible. This is the true national challenge and should

be the mission undertaken.

In 1976, two short years after we were all waiting in line to get gas, the then President Carter gave a speech announcing an energy program that he described

as the ‘‘moral equivalent of war’’. At that time there was still plenty of easy to discover and to recover oil, and, plenty of excess capacity at OPEC’s disposal as well

as outside OPEC.

Both Alaska and North Sea oil were in a full upward production swings. But today?. Today, we are not as fortunate. There is plenty of evidence that has emerged over the past decade that the epoch for easily, and cheaply discoverable oil is behind us now. Yet the world demand for

liquid fuels has been steadily increasing and has already approached available maximum production. This steadily increasing demand ‘‘which has been underestimated

by many experts, has been to satisfy the new needs for liquid fuels in the newer

emerging economies of Eastern Europe, India, Southeast Asia and China. This past year alone, the combined demand increases by both China and India have exceeded the yearly, daily average net new production capacity additions from

non-OPEC sources. This newer capacity additions had been averaging about 1 million barrels per day every year for the last 10 years, and are expected to accelerate

to about 1.5 millions barrels per day per year, for the next several years. But this

is not enough, so our dependence on OPEC oil will continue to increase, and so thus

our vulnerability.

Therefore, we have to expect that without increases in new liquid production from

other sources, such as shale oil, supply growth will constrain future demand growth,

and our economic growth and well-being will slow down or deteriorate. The only

time, supply additions will grow faster than demand, would be if there is a severe

recession.

How can we as a nation sit and watch impassively while the mayor oil companies

are all loaded with tons and tons of cash, not knowing what to do with it, while

our oil shale resource remains unused?

Does it not, therefore, make sense for us to create the ‘‘right’’ incentives for the

oil companies to invest all that accumulated cash? Does not this accumulation of

cash signal two evident warnings—One, that the oil companies are short of available new prospects, and two, that whatever is available is considered too risky for

50

them to invest? Does this not suggest that this is an unsustainable national security

situation?

Our responsibility goes beyond proposing to Congress a limited program to develop the technology to extract the liquid from the rock, it goes to propose a comprehensive program that addresses all the issues and create the necessary incentives and guarantees so that our cash loaded oil companies proceed to the intense

and responsible industrial undertaking of massively extracting the oil from the rock

from the entire shale and tar sand resource. A maximum priority of our National

Security.

If adequate market incentives are in place that eliminate or reduce market risks

and assure reasonable profits, the oil companies will come up with the technology.

We will shorten the time for the availability of the fuel from the shale and the tar

sands by many years.

The Bureau of Land Management (BLM) must again make available the land containing the shale oil to these companies. Our government must provide a guarantee

that each barrel of liquid fuel that goes into our domestic pool and that was extracted from U.S. shales or tar sands is guaranteed an indexed minimum price that

reduces investment risk and provides an adequate return to the investor. My educated guess is that that price today is equivalent to $50.00 or $60.00 a barrel of

crude. This guaranteed minimum is needed so that there is not a repetition of the

earlier mistake with the shale oil program. The extraction projects were abandoned,

when the price of crude dropped and when the newly elected President Reagan cancelled the subsidized purchases of fuel from U.S. shales by the Department of Defense. An accelerated depreciation schedule until the year 2035, that would allow

writing off in less than three years the equipment required to extract the oil from

the rock, should be authorized to stimulate industry to make the enormous investment required. Finally a ten year tax holiday beginning on January 1, 2006, ending

on December 31, 2015 to incentivate industry to jumpstart the reasonable commercial development of the resource.

I want to share with you my experience in the ethanol for fuel program which

was successful and very profitable. It is important that we draw lessons from the

past so that we can set the right course from the beginning. My contributions were

essential to getting the alcohol fuels program going. Later my commercial activities

continued to be profitable to me and many others. I had the opportunity to watch

from the sidelines what happened to the alcohol fuel program. Mainly its successes.

Successes and failures, also occurred in the earlier shale oil program. We cannot afford for the sake of our national security and our economic survival to make the

same mistakes.

Congress came out with a program which incentivated demand and use by exempting from the excise tax on motor fuel each gallon blended with 10 percent anhydrous ethanol. This was sufficient to encourage a large grain processing company

to begin making the investments in the distilleries to manufacture the ethanol. For

a while there was only one big producer, since the other large grain processors did

not believe that the incentives would be politically sustainable over the long term.

The one company accepted the political challenge, and today, 25 years later all of

them are in the business and the incentives continue to exist. And the excise tax

exemption continues to exist, with additional incentives for the production of ethanol.

If similar market incentives were made available to each barrel of liquid fuel produced from American shales or tar sands, similar considerations would be given in

the board rooms of the big oil companies. It is my belief that the risk that these

incentive could be discontinued could be managed by a coalition of blenders, refiners, consumers and Americans concerned with the security of our transportation

system. Let’s not forget that what the American consumer wants most is the ability

to gas up, and not wait in line. They are willing, as demonstrated by the recent experience over the last few months, to pay well over $2 per gallon as long as that

gasoline is available to them. So supply reliability is upper most in the consumer’s

mind, more so than prices. Europeans, have gotten accustomed at paying over $5/

gallon, and our consumers will eventually do likewise, if we can prove to them that

the alternatives are long lines at the gas stations.

It is time to do what must be done. It is today that it must be done. Ten years

from now it will be too late. We owe it to the brave young men and women that

are risking and losing their lives defending our freedoms. Let us do our part.

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Mr. GIBBONS. And gentlemen, before you sit, we still have that

procedure to go through of swearing you in. So if you will, just

raise your right hand and repeat after me.

[Witnesses sworn.]

Mr. GIBBONS. Let the record reflect that our witnesses answered

in the affirmative.

We turn now to Mr. Russell George, Executive Director, Colorado

Department of Natural Resources. Mr. George, welcome to the

Committee. Thank you for coming this far to help us better understand this issue. The floor is yours. We look forward to your testimony.

May I say, also, that we have a little clock in front of you that

shows five minutes. If you can sum up, we have your written statement, which will be submitted in complete order for the Committee. So if you want to summarize and talk a little bit about your

ideas in the five minutes you have, that is also very helpful.

So Mr. George, the floor is yours.

STATEMENT OF RUSSELL GEORGE, EXECUTIVE DIRECTOR,

COLORADO DEPARTMENT OF NATURAL RESOURCES

Mr. GEORGE. OK. Thank you, Mr. Chairman and members of the

Committee.

I did take advantage of your rule that allows me to add appendices to our own comments. And because we’re talking about state

and local government aspects here today, I took that opportunity

to enclose a recent statement from a consortium of local governments in northwest Colorado that I thought was very important to

share with you. And I’m quite confident that as we talk about

Utah, local government views will be very similar and very compatible. So I would urge you to also note that that document is present

in my remarks.

A very complicated subject, very hard to summarize in the few

minutes; so I’m going to just bounce across what I think are the

main points that we think about at the state level. And certainly,

I want you to know that Colorado is a very willing partner in the

development of this resource. We regard the resource as abundant,

as we’ve been hearing here today, and its development very much

in the national interest.

But we’re very specific about some conditions of how the development of that resource should proceed. First, we would agree with

others that technology and environmental oversight must be very

rigorous, from beginning throughout.

Second, we believe that development must use the best available

practices, best management practices, to minimize all impacts that

come from this kind of heavy industry.

Next, we believe that state and local needs must be anticipated

ahead of time, and some arrangement made ahead of time for funding; and that development on public land—and in northwest

Colorado, this will occur mostly on public land—must be prioritized

by resource and region. Just noting that in the last 20 years, since

we had the last oil shale effort, we now have on this same property

a rapidly expanding natural gas development. And there are other

resource uses also existing that all need to be prioritized, and allow

all to work together.

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Also, it’s our view that the cumulative impact of mineral and

energy development on all public lands, as well as private lands,

must be mitigated.

Colorado has consistently supported the development of the oil

shale resource in western Colorado. But we’ve insisted, and would

again insist, that the projects be fiscally and environmentally

sound from beginning and throughout, and that the communities,

local governments, do not incur extraordinary economic burdens.

The development of the energy project must pay ahead of time its

own way, so that the remaining communities can keep pace but not

have to generate other resources to respond.

Oil shale leasing on top of existing energy development and

changing land uses—for example, we have increasing tourism and

recreation; we have an expanding urban population throughout

western Colorado—all of this may put more pressure on an already

fragile ecosystem and public temperament.

The response to that, of course, is we need to be careful, be respectful, as we go forward. We think we should go forward, but

paced and respectful is the way to do that.

So there are three things that we think we can do and should

do. Federal financial support must be sustainable over an extended

period of time, to encourage private sector investment. Also, a thorough environmental review process must occur. And, a financial

safety net for local governments that allows for growth to pay its

way and allows front-end financing.

Three things should not occur. This is something we’ve learned

from our history and our past mistakes. One, processes that preempt or supersede local and state land use and environmental

processes should not occur. In other words, we can’t have the Federal system saying, ‘‘We’ll supersede local and state rules and requirements.’’ We can do this together in a type of joint review

process, but not one over the other.

The development of technologies cannot occur without adequate

oversight. We need to ensure both public acceptance and environmental compatibility.

And also, the national effort must address financial and infrastructure needs at the local level. And we have a number of ways

of doing that. There is a revenue stream, because this is public

land, that can help us do that.

I think that’s enough time for now. I’ll be available for your questions, Mr. Chairman. Thank you very much.

[The prepared statement of Mr. George follows:]

Statement of Russell George, Executive Director,

Colorado Department of Natural Resources

Mr. Chairman, thank you. I appreciate your invitation to participate in this hearing. I am Russell George, Executive Director of the Colorado Department of Natural

Resources. As the lead state agency responsible for natural resource management,

I appreciate the opportunity to provide our perspective on renewed oil shale development in Northwest Colorado.

We are excited to be partners in this effort to move our great nation closer to

energy independence. With perhaps as much as two trillion barrels of oil locked in

the shales of western states, this vision is achievable in our lifetimes.

As a lifelong resident of ‘‘Shale Country’’, I would like to share some thoughts

with you on three decades of lessons learned regarding the impacts and possible

tools to manage the development of the resource successfully.

53

Background Principle

The State of Colorado has consistently supported the development of oil shale

resources in Northwest Colorado since the Arab Oil Embargo of the early 1970’s.

Our focus has been on making sure that the projects are fiscally and environmentally sound, and that the communities do not incur extraordinary economic burdens. As history has shown, if development pays its way, the community impacts

are less if the projects do not materialize.

History

Let me summarize the key elements of the oil shale development cycles of the last

three decades.

Oil Shale Lease Bids. The federal government leased two tracts in each state—

Colorado, Utah, and Wyoming—in the early 1970’s. Bonus payments accompanied

each of these leases—that determined the winning bid for the lease. Half of those

bonus payments were distributed back to the state. The General Assembly established the State Oil Shale Trust Fund and Program which developed planning and

coordination mechanisms for federal, state, and local governments and provided

funding for designated local government services and projects ($100+ million). The

goal was to mitigate the ‘‘boom town’’ syndrome.

The Energy Mobilization Board. As the energy crisis worsened in the late

1970’s, the Executive Branch of the Federal Government pondered a national board

that could declare the development of a resource in the national interest—thus preempting local land use regulations and much of the state permitting process. The

Western Governors, in particular, led the effort to oppose this preemptive measure

by the federal government. The Board never materialized.

Synthetic Fuels Corporation. Congress funded the Synthetic Fuels Corporation

to initiate oil shale projects in a manner that would allow several technologies to

develop simultaneously. Congress allocated $15 billion in price guaranties and price

incentives that were competitively awarded on a multiple year cycle. In a large part,

this approach made the federal government a partner in accelerated technology development.

Joint Review Process. In response to the national focus on the oil, gas, oil

shale, coal and uranium resources in Northwest Colorado, Colorado developed the

concept of a Joint Review Process. That process consisted of a centralized facilitation

of the permit process at the local, state, and federal level. The Joint Review Process

Program determined the timelines of the various required permits, coordinated the

scoping process for the environmental impact statements, and facilitated public

hearings and public comments. The overall coordination of the effort could allow for

the application of several permits for an individual project to occur simultaneously.

All the major oil shale projects, associated power plant projects, and coal mines used

the Joint Review Process.

Cumulative Impacts Task Force. In addition to the permitting and environmental analyses related to the simultaneous development of multiple resources, the

State of Colorado was also concerned about the fiscal impact to individual communities and counties in high development areas. To that end, the state developed the

concept of the Cumulative Impacts Task Force that modeled the budgets, revenues

and expenditures of 104 jurisdictions in Northwest Colorado. The key task was to

determine what projects would cause what economic impacts to what jurisdictions

in what years based on different population and development scenarios.

The effort proved to be extremely valuable when Exxon closed its Parachute

Creek facility. At that time, because of the front-end analysis work, the distribution

of energy impact funds, and the use of the Oil Shale Trust Fund, long-term economic impacts were manageable. At the time of the Exxon pullout, only one school

district had a multiple hundred thousand dollar residual impact.

DOE Technology Partnership. In the late 1980’s, Occidental Oil under the

leadership of Armand Hammer, proposed the cooperative development of an improved oil shale technology at the C-b Oil Shale Tract in Northwest Colorado. This

was to be a 50-50 partnership of Occidental and the Department of Energy. Through

the work of the state, the Department of Natural Resources, and the Associated

Governments of Northwest Colorado, a seven-year commitment of funds was secured

from the Department of Energy for this demonstration project. The other oil shale

states contributed to the technology analysis for the project. The primary market

was not for processing shale oil into motor fuels, but as chemical feedstocks for

other uses. The project terminated upon the death of Armand Hammer when

corporate directions were changed.

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Technology and the Environment

In the 1970’s and 1980’s, the Project Independence Technology Assessments and the Synthetic Fuels Corporation financial plan focused on both in-situ (in the

ground), surface, and modified in-situ technologies. The goal for synthetic fuels was

an industry that would convert coal, tar sands, and oil shale to liquid fuels at a level

of two million barrels per day by 1992—the majority of which would have come from

western oil shale.

The dimensions of the proposed technologies were immense. A surface oil shale mine associated with a minimum-sized (50,000 BPD) commercial plant would be

comparable in size to the largest iron and copper mines in the world. This scale was

necessary since it required 2.5 tons of rock to produce one barrel of oil. Underground (in-situ) processes would have recovered less resource. Such mines would need to produce as much as 100,000 tons of rock each day to support a 50,000

BPD facility. The ore would be processed (retorted) above ground. Disposal of the

spent shale in some cases would have filled valleys. The most advanced technology was modified in-situ. That technology mined a por- tion of the deposit by conventional methods for surface processing. The remaining

shale was then fractured by underground detonations, the rubble ignited, and the

oil transmitted to the surface. This process would recover less, but with less surface

impact.

As you can see, the surface area requirements for mining, retorting, or spent shale disposal were significant. Costs were enormous even in 1980 dollars—an average of $2 billion for each 50,000 BPD plant. Based on the applicable 1977 Clean

Air Act standards, production in NW Colorado would have been limited to 400,000

BPD. Water requirements for a 50,000 BPD facility would require 8500 acre-feet per

year of water. In the end, the oil shale industry collapsed of its own weight—given the volumes of material to be removed and processed, the enormously fluctuating world oil price,

and the lack of a consistent national vision for the development of this resource that

could focus private capital investment.

While we do not know the specifics of the technologies that may be pursued over the next decade, we do know water availability, materials handling, power requirements, and transportation networks must be assessed in detail and the impacts

mitigated appropriately.

What Worked—What Didn’t Work

If the Federal Government is to contemplate a renewed oil shale effort, it must

do so based on the lessons learned over the past thirty years. While the technologies

are changing, so are the characteristics of ‘‘energy country’’ in Northwest Colorado. As in the 1970’s, we have record coal production that is straining existing trans- portation networks. We have record natural gas production levels and increasing

permitting for natural gas development. The diverse development of this resource

has dotted the landscape, increased truck traffic on county roads, and access to the

resource has impacted many private landowners where the surface and mineral estates are severed. Additionally, there is a growing public sensitivity to in-situ activities, such as fracking with ‘‘proprietary fluids’’.

This development overlaps an area with increasing tourism and recreation opportunities and an expanding urban population. Oil shale leasing on top of this existing

network of energy development and changing land uses may put more pressure on

an already fragile ecosystem and public temperament.

We do not control world oil markets, nor do we control the actions of OPEC.

Therefore, the development of oil shale cannot be purely price driven. It must be

a commodity of national interest developed on public lands in the national interest.

That implies a prioritized use of public lands for the development of specific

resources. Federal financial support must be sustainable over several decades to encourage private sector investment. An environmental review process must be thorough. A financial safety net for local governments that allows for growth to pay its

way, and allows front-end financing of some infrastructure needs and analytical

tools, is essential.

All this said, the implication is that bonus lease payments from federal leases for

local government facilities and services are good. Long-term federal financial support that fosters private investments is good. A coordinated permit process with adequate public input is good. And analytical tools that allow state agencies and local

governments to anticipate the timing and amount of revenues for impact mitigation

are essential.

What will not work are processes that preempt or supersede local and state land

use and environmental permit processes. What will not work is the development of

technologies without adequate oversight to insure both public acceptance and

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environmental compatibility. What will not work is a national effort that does not

address financial and infrastructure needs at the local level.

Colorado Recommendations

Colorado is excited to be a partner in the development of a resource that is both

abundant and in the national interest. But it does intend that technology and environmental oversight be rigorous, that development use the best available practices

to minimize impacts, that state and local needs are anticipated and funded, that development on public land be prioritized by resource and by region, and that the cumulative impact of mineral and energy development on both public lands and private lands be mitigated.

Oil Shale Lands Suitable for Development. Given the density of natural gas

and coal development in some areas of NW Colorado, the need for recreational/wildlife habitat/undeveloped areas, and the network of privately held oil shale lands

that did not exist in the last boom, the federal government must determine those

areas where oil shale development could be accommodated in a manner that is least

disruptive to communities and existing activities. Not all types of resource development can occur everywhere. The carrying capacity of the land, communities and infrastructure must be evaluated. That will determine the suitable areas for coal, natural gas, and oil shale development.

One type of mineral and energy development today, may preclude or limit another

type of resource development tomorrow. We cannot forget that a consequence of the

oil shale pull-out of the 1980’s, and the sustained soft energy market in the 1980’s,

has been the transformation of the NW Colorado economy from an energy base to

a tourism, retirement, second home and recreation base—and public attitudes have

changed as well. That cannot be underestimated if accelerated development is to resume.

The lead federal agency in this new effort should provide this cumulative impact

analysis and identification of areas suitable for oil shale development as an element

of any development and leasing plan. Furthermore, we should insist that parcels

available for leasing should be of sufficient size and number to ensure that operations are commercially viable and similarly situated with lease programs for other

mineral and energy resources.

Oil Shale Lease Bids. Along with an oil shale lease process that generates frontend revenue and production royalties for the federal government, the 1970’s concept

of the bonus bid should be applied to any oil shale leases in the future. For the

tracts leased in Colorado, a sum of over $100 million was collected and distributed

to the impacted counties. This economic cushion is essential to community stability,

and the ability to withstand the economic shock of a project termination.

The federal leasing program to be implemented in this new effort should insure

that the bonus bid concept continues, and the proceeds are distributed to the state

in which the lease is located.

Federal Financial Support. Several options have been pursued through the

years to fund technology development. Tax credits have been one avenue that

proved very successful for coalbed methane development. Incentives like those of the

Synthetic Fuels Corporation have been another. The DOE Demonstration Project

route like that at Logan Wash is another. And the DOE cost-share like the Occidental C-b Oil Shale Project is another.

Oil shale technology development is still fraught with uncertainty. Once a technology appears promising, it must be field tested. And then limited commercial scale

production may occur. Collectively, this could span a decade or more. But the lesson

learned from the 1970’ and 1980’s is that any financial incentive program must have

a duration comparable with the timeframes for private investment that include a

realistic timeframe for technology development and implementation, or the private

dollars will not come.

The Department of Energy should poll the industry prior to the passage of any

legislation to determine the adequate minimum timeframe to encourage private investment.

Coordinated Permitting Process. Given the economic transformation of NW

Colorado in the past 20 years, coupled with the increasing level of natural gas development, a coordinated and integrated permitting process is essential. The environmental and land use permitting process can be complex and time-consuming when

all the local, state and federal requirements are considered. Coordinating the

process is essential, and cannot be underestimated. For the requirements in place

20 years ago, the average timeframe to permit an oil shale project was about 42

months. Some processes have become more complex since then—and certainly public

interest is more organized and focused.

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As a reminder, the Colorado Joint Review process grew out of the concerns raised

over the concept of the Energy Mobilization Board. That Board would have had the

power to preempt local and state regulatory requirements in the national interest.

The reaction in the West was to coordinate and streamline, not dismantle, the existing process. And it worked. Attempts in recent years to truncate the process have

been met with public criticism and lawsuits. Such efforts have proven to be counterproductive to the goal of developing these important resources.

The Colorado Joint Review Process is an option that the federal government

should consider fully funding, or partially funding along with industry, to assure a

rigorous review with adequate public input and consultation.

Economic Impact Analysis. Once the development area is determined, a procedure must be established to evaluate economic impacts at the local level. The federal government should fund, either through the bonus bid process or authorizing

legislation, a concept similar to the tools used by the Cumulative Impacts Task

Force. This analysis would not only guide the timing of needed permanent and temporary community services and infrastructure, but also allow local governments to

establish fiscal tools that would insure that growth could pay its own way.

The true cost of the development of strategic resources such as oil shale must be

evaluated not only in the context of their technology and development costs, but also

the costs and benefits to the community. Securing a safety net is the primary lesson

of the last bust.

Conclusion

It is essential that Congress consider the life cycle of oil shale development as it

contemplates a renewed national oil shale effort. Only this view will portray the

complete picture, so that the appropriate technology, environmental and economic

structures can be defined and funded for a successful long-term effort. I look forward to working with you in the months ahead.

APPENDIX A

A Local Government Perspective on Federal Oil Shale

Research and Development Efforts

Mr. Chairman and Members of the Committee:

My name is Jim Evans, Executive Director of the Associated Governments of

Northwest Colorado (AGNC), representing cities and counties in the 5-county region

of Garfield, Mesa, Moffat, Rio Blanco and Routt Counties in Northwest Colorado.

On behalf of our local governments I want to express our appreciation to your committee for asking our local government views on the development of oil shale technology.

Our local government association was formed at the start of the last oil shale development cycle as the ‘‘Regional Oil Shale Planning Commission’’ with the specific

charge to address the socioeconomic and environmental impacts of a potential commercial scale oil shale industry. Now, renamed as the Associated Governments of

Northwest Colorado, we are still concerned with this issue. This time around it appears that our region will need to address the potential growth and infrastructure

impacts of oil shale development on top of the socioeconomic impacts already occurring in our region from record levels of natural gas, oil and coal production. With

estimates of from 600 billion barrels to 1.8 trillion barrels of recoverable oil from

shale in our region, we recognize the national interest in developing the technology

for this resource. In particular, the needs identified for the Department of Defense

for a secure domestic source of fuel make us realize that the importance of the

resource cannot be ignored. We also understand the potential economic benefit development of this resource can play on our national balance-of-trade and G.N.P.

Since more than 80% of the oil shale resource is located on federally-owned public

land and recognizing that the future development is driven by national interests,

local governments in our region believe the federal government must play a lead

role in addressing these socioeconomic and environmental impacts and costs. We do

not want to see local governments (and local taxpayers) stuck with the costs of new

infrastructure and the mitigation of environmental impacts. So we are pleased to

see that your Committee and the Department of Energy as we begin this next cycle

in Oil Shale development are addressing these issues up front. This is a refreshing

difference than the start of the last cycle. Back then, with an oil embargo facing

the country, Congress first responded with a proposal for an Energy Mobilization

Board with the power to declare Northwest Colorado as a ‘‘National Sacrifice Zone’’.

Fortunately, that proposal did not make it all the way through Congress and as my

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following testimony indicates, we learned a lot during a fairly painful 18-year boom/

bust cycle prematurely attempting to develop commercial scale projects.

This time we appreciate the ‘‘Research and Development’’ type approach being put

forward by the Department of Energy, and by the recognition of your Committee

up front that you are looking for development of an environmentally friendly technology, and an approach not dependent upon the price of oil.

Because we support your stated approach it gives me the opportunity to say,

‘‘I am from the Local Government, and I am here to help you.’’

I would like to start my help by submitting for the record the following resolution

from Club 20, the community based Colorado organization representing cities, counties, businesses and citizens throughout Western Colorado. This resolution was

unanimously adopted by the Club 20 Board of Directors endorsing a Research & Development program as being considered by your Committee.

Club 20 Support for an Economically Viable And Environmentally Sound

Oil Shale R & D Program

Whereas Oil shale may still be the largest untapped resource available for transportation fuels;

Whereas the richest deposits of oil shale in the world are located in Northwestern

Colorado and Eastern Utah;

Whereas a DOE report indicates that oil shale development may still be important

for our country’s National Security (as an alternative to imported oil) and for

our Economic Security (to improve our balance of trade); and

Whereas without a well conceived federal R & D program this region may again

someday be faced with another crisis oriented commercial scale oil shale program.

Now therefore be it resolved that Club 20 supports research and development efforts

leading to an economically viable and environmentally sound oil shale program.

Further, Club 20 supports DOI/DOE/DOD efforts to develop a national oil shale policy and long-term R & D plans.

APPROVED, FEB. 15, 2005

CLUB 20 ENERGY COMMITTEE

CLUB 20 NATURAL RESOURCES COMMITTEE

APPROVED, APRIL 1, 2005

CLUB 20 BOARD OF DIRECTORS

Background: Last Oil Shale Development Cycle 1974-1992

• The last oil shale cycle started with the Arab Oil Embargo in 1974. This was

a Sudden Oil Shortage, resulting in long lines at gas pumps, temporary high

gas prices, and a staggering impact on the U.S. Auto Industry and U.S. economy, aggravated by gasoline rationing.

• Congress responded in a crisis mode.

• The first industry proposal to local government was: Get out of the way and

we will develop Oil Shale! Congress responded with a Proposal for Northwest

Colorado to be declared a ‘‘National Sacrifice Area’’, including an Energy Mobilization Board with power to override Federal, State and Local environmental

and land use laws. State and Local governments responded on an adversarial

basis.

• President Jimmy Carter instead got Congress to establish the Synfuels Corp.

with $15 Billion in price guarantees and price incentives.

• In our region 12 projects were underway at peak of cycle (either in planning,

permitting or construction).

• An Exxon White Paper suggested a socioeconomic impact of a one-million population increase in NW Colorado by 1990. It appeared that all the construction

workers in USA would be required for the effort if all the companies went forward at the same time.

• The Colorado projects reaching construction or testing: Exxon Colony Project,

Unocal, Oxy (CB), CA consortium. The DOE Anvil Points facility in the meantime was pretty much abandoned, except for a look at an asphalt additive byproduct.

• The cycle collapse (Bust) started May 2, 1982 with an abrupt Exxon Colony closure. In the Boomtown Blues book, this event was blamed for the U.S. and

worldwide recession.

• The Unocal project & Oxy continued their efforts through 1990-92. This somewhat mitigated the ‘‘bust’’ cycle. At the peak of the cycle, the combined population of the 2 most impacted counties (Garfield and Mesa) increased from 1981

58

to 1983 by 12%, from 112.0 thousand to 125.6 thousand. Then in the next 2

years the combined population dropped back to 111.8 thousand.

• Congress then overreacted and shut down virtually all oil shale research programs, despite recommendations from many sources that research and development activities should continue.

Was Anything Learned During This Cycle? Yes!

• Congress in 1975-76 enacted Mineral Leasing Act Amendments at the urging

of States and Local Governments. The State share of federal royalties increased

from 37 1/2% to 50% with priority for local governments impacted by Mineral

Leasing activities, such as Oil Shale, Oil, Natural Gas and Coal.

• Congress enacted Payments-In-Lieu of Taxes (PILT) Act to compensate counties

for tax exempt federal land thereby giving direct assistance to rural public land

counties.

• States in turn enacted Severance Taxes, also with a priority to address socioeconomic impacts.

• Local governments in turn enacted Major Impact Land Use Mitigation Ordinances.

• The Colorado Joint Review Process (CJRP) was initiated. This was a voluntary

program designed to coordinate and speed up federal, state and local permitting.

• Local Government Energy Impact Programs were established by States with the

new Revenue from Mineral Leasing and Severance Taxes. These programs

today address the ongoing impacts of mineral development. The Energy Impact

Program in Colorado actually started with the formation of the Regional Oil

Shale Planning Commission (now AGNC) and the enactment of the Oil Shale

Trust Fund (OSTF). From the OSTF $75 million plus interest was allocated to

NW Colorado counties. The $75 million was Colorado’s 37.5% of federal Oil

Shale leasing bonuses.

• Negative impacts of the abrupt Exxon Colony Project closure actually resulted

in a positive turnaround on State/Local/Industry relationships and communications as Unocal and Oxy proceeded with their projects with local support.

• Local governments also supported continuation of the Unocal and Oxy projects,

including proposals to turn them into federal oil shale technology demonstration

projects.

• Support for a Federal Oil Shale R & D program was generated in Colorado,

Utah, Wyoming, Kentucky, Illinois and California, but to no avail.

• New Paraho Corp. temporarily continued oil shale asphalt testing at Anvil

Points to demonstrate the byproduct approach to make oil shale economically

viable. Some of the asphalt test strips are still in place with no repairs required.

Local Government Advice to Industry for the Next Oil Shale Development Cycle:

Communicate! Communicate! Communicate!

The Shell Oil Shale Project is on the right track. Shell Oil is the only company

in Colorado who is currently continuing with field-testing. Local governments appreciate these efforts. Their efforts have included ongoing meetings with County Commissioners, Cities, school districts and citizen groups. They have sponsored and organized town meetings. These were very successful from a local perspective. These

should continue at the beginning of each phase of an R & D program.

The Department of Energy also appears to be on the right track. The Naval Petroleum and Oil Shale Reserve Office of DOE has prepared a well documented and

thorough report indicating the National interest in developing the oil shale resource

(trade deficit impact on the economy and national defense interest in a secure oil

source.) We believe addressing the socioeconomic and environmental issues in the

DOE proposal for a National R & D program and demonstration facility is on target.

Virtually all groups and industry involved in the last oil shale cycle have recommended the need for an ongoing federal oil shale research program.

These Groups and individuals back in 1991 were: The Rocky Mountain Oil & Gas

Association, The Western Oil Shale Action Committee, Club 20, Associated Governments of Northwest Colorado, The Garfield County Citizen Alliance, Governor Roy

Romer, Senator Tim Wirth, Representative Ben Campbell, The Rebuild America

Foundation, The Alternate Energy Research Institute, and The Rocky Mountain Institute. There may have been others. These were the ones that I was aware of.

Recommendation to Address the Socioeconomic Impacts of the Next Oil

Shale Cycle

With the renewed interest in oil shale development, the Department of Energy

needs to provide funding for socioeconomic programs to:

• Assemble and update impact data from the last cycle.

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• Identify appropriate computer systems/models to assess projected impacts.

• Development of baseline economic data for current activities.

• Help identify and provide revenue streams for local/state government services/

infrastructure potentially impacted by oil shale development.

DOE also needs to identify and recommend appropriate federal, state and local

policies to encourage prudent and environmentally sound oil shale development.

Recommendation to Address Environmental Impacts of Oil Shale

Development

The DOE Demonstration program/projects should address:

• Surface disturbance impacts and ongoing reclamation requirements.

• Air Quality impacts.

• Water Quality and Quantity impacts.

• Wildlife protection and mitigation requirements.

• Employee health, safety and training needs.

Regular communications with news media and environmental groups should address the potential environmental impacts of various oil shale technologies.

The Colorado Department of Public Health and Environment should be actively

involved in monitoring air quality and water quality impacts.

The State of Colorado Department of Natural Resources and its Wildlife Division

should be actively involved in these reclamation and wildlife issues.

The Department of Interior should develop a leasing program to accommodate access to oil shale for research and demonstration project purposes. Any commercial

scale leasing proposals must include provisions that recognize the ‘‘carrying

capacity’’ concepts for socioeconomics and the environment that are part of the BLM

Piceance Basin Resource Management Plan.

Recommendation to Provide the Funding for Oil Shale Research Costs and

Incentives

We believe it is fortunate that Congress may have already provided a potential

source of funding for Oil Shale R & D efforts. This revenue may be currently available from the Naval Oil Shale Reserve (NOSR) lands themselves located in Northwest Colorado. As indicated in the attached letter from the Department of Interior,

some $43.7 million may be accumulated by March 2007 in a U.S. Treasury account

from the current natural gas leases on their NOSR lands. These NOSR lands were

transferred by Congress from DOE to the Department of Interior with a Congressional priority established for natural gas leasing.

Some of these funds, estimated at $5.8 million, are earmarked for environmental

cleanup of the Anvil Points spent shale pile. Otherwise, we believe Congress has the

opportunity for the remainder of these funds to be made available to address the

socioeconomic and environmental aspects of oil shale development in Northwest

Colorado.

In the future, more revenue should be available from this source. According to industry estimates, additional leasing of the NOSR lands could produce leasing bonuses of up to $360 million (to be shared 50% federal and 50% state) plus ongoing

production leases of an estimated $32 million annually for at least 20 years. That

would be another $640 million total also to be split 50/50 federal and state. Congress should establish a priority to address oil shale and other energy development

impacts in Northwest Colorado from these leasing revenues.

We believe this type of funding is necessary to make sure the DOE research and

demonstration projects can proceed without interruptions from fluctuations in the

price of oil.

Thank you for this opportunity to testify. I would be happy to answer any questions you may have.

JIM EVANS, AGNC EXECUTIVE DIRECTOR

Response to questions submitted for the record by Russell George,

Executive Director, Colorado Department of Natural Resources

We appreciate the State of Colorado’s position, as stated in your testimony, that

through the production of oil shale and other resources our Nation can become

energy independent in our lifetime. We thank Colorado for its commitment to support production of the vast oil shale resources within its boundaries. We agree with

you that this must be done in a responsible manner and we look forward to the Federal Government working closely with the western oil shale States as we move to

produce this vast resource for the American people.

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1. What is the source of funds that the Congress should look to in order to provide the financial resources to compensate for socioeconomic and environmental

impacts?

Lease Bid Bonus Payments collected and distributed in advance are the most ef- fective tool for the front-end financing of socio-economic impacts. As production develops, federal royalties and state severance taxes can also reimburse local communities for such impacts. This model worked in the 1970’s/1980’s, and should still be

effective. This approach is validated in the testimony provided by the Associated

Governments of Northwest Colorado.

Environmental impacts are the responsibility of the permittee, and are embodied in the stipulations of the necessary federal, state and local permits required for such

a project to proceed. For this reason, the existing public permitting processes should

not be short-circuited to expedite production. Their timeframes allow for adequate

public review and comment, as well as the regulatory tools to mitigate impacts.

2. Given the fact that all resource development is contingent upon the economics of production, which is primarily derived from the price the product can command

and the costs of production, what can the Federal Government do to ensure that

oil shale production is economical?

The State of Colorado is not convinced that it is the role of the federal government to make oil shale production economical. The economics of alternative fuels, like oil

shale, are ultimately set in the international marketplace. However, it is an appropriate role of the federal government to support technology development, that can

be done in three ways. First, through the development of oil shale technologies at

federal facilities—such as the national laboratories. They played such a role in the

1970’s/1980’s effort. Second, the federal government can make federal lands and facilities available to the private sector to test oil shale technologies. All NEPA requirements would prevail. Finally, the federal government could make technology

development grants available for private technology development projects. All these

actions would in effect subsidize the cost of technology development, and ultimately

the cost of the product.

3. What policies of the State of Colorado will ensure that the local governments receive their fair share of the State’s one-half of Federal royalties and the State

severance tax on the production of Federal oil shale?

The appropriate state statutes guiding federal royalty distributions and state sev- erance tax distributions have been in place since the 1970’s. There is no need for

modification at this time.

4. How do you recommend that coordination with the State and local governments on leasing and production be handled?

It is the intention of the Department of Natural Resources to seek reauthorization

of the Colorado Joint Review Process in the 2006 legislative session. That process

was developed in the 1970’s partially in response to the oil shale boom. It creates

a forum for public participation in the scoping of federal leasing and NEPA documents, as well as coordinated public review and comment in the federal, state and

local permitting process. The core funding would come from the state severance tax

fund. The federal participation will be funded through the relevant federal agencies,

and the project proponents would fund the costs of the process specific to their

project. Regulatory oversight under existing federal, state and local laws will guide

the production and reclamation phases.

5. What mechanisms should be put in place for engaging communities in federal

planning and program development? For example, would Memoranda of Understanding with Regional Planning councils be of value?

As outlined in Question 4, the principal state process will be the Colorado Joint

Review Process for leasing and permitting decisions at the federal, state, and local

level. Local governments will coordinate the socio-economic impact analysis using

funds distributed through the Bonus Lease Bid Process. There are no regional planning councils in Colorado. Their equivalent would be councils of government which

may not have energy impacts within their purview. Therefore, the distribution of

Bonus Lease Bid Funds as guided by state statute would ensure that the affected

local governments would have access to the appropriate funds.

6. We have heard proposals to direct mineral lease royalties from the Naval Oil

Shale Reserves in Colorado to the planning and impact mitigation efforts of

Colorado, Utah and Wyoming. Would Colorado support this proposal?

Assisting in local and regional impact planning and mitigation efforts is something Colorado has always supported. In the short-term Colorado would support

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using royalties from NOSR 1 and 3 for these purposes both here and in neighboring

states, until such time the federal government is fully reimbursed for the infrastructure costs and environmental restoration work that was required as part of the

transfer legislation. At that point, and we understand the full $43 million will be

realized in 2007, it would be necessary to resume the normal state share royalty

distribution formula for federal minerals produced in NOSR 1 and 3.

7. Oil shale may provide long-term energy security for the US. Would Colorado support program planning and managing of this resource as a Petroleum Reserve?

Yes, as long as the management of such a reserve would be subject to adequate

public participation including opportunities for public review and comment. Oil

shale country in Colorado is also the site of competing resource development (coal,

oil and gas), and competing land uses (recreation, agriculture, and mineral and

energy development). This is the basis for Colorado’s request that the federal government identify those areas suitable for oil shale development in light of competing

land uses. The competing uses, as well as community needs, are the basis for a

Colorado Joint Review Process to allow adequate public input on complex issues

such as a Petroleum Reserve.

Mr. GIBBONS. Thank you very much. And we certainly appreciate

the State of Colorado’s position on this and your commitment and

support for developing this, as well.

We turn now to Mr. Michael McKee. Commissioner, welcome. We

are happy to have you. I know it is a long way from Uintah

County, Utah, here to be with us, and we certainly appreciate that.

Welcome. The floor is yours.

STATEMENT OF MICHAEL J. McKEE, COMMISSIONER,

UINTAH COUNTY, UTAH

Mr. MCKEE. Thank you, Mr. Chairman, and Committee members

and staff members. And greetings from Uintah County, Vernal,

Utah—Utah, dinosaur land.

As has been brought out, there are vast energy resources in our

area; including oil and gas, gilsonite, coal, tar sands, and oil shale.

This past year, the Vernal BLM field office was the second-busiest

field office in the United States, processing approximately 700

APDs, or Approved Permits To Drill. This past month, they

processed over 100. So they’re clicking right along.

Moving to oil shale real quickly, a significant portion of the oil

shale resources of the Green River formation are located in Uintah

County, Utah. These resources are believed to be the most concentrated accumulations of hydrocarbons on Earth.

The commercial attractiveness of these zones measure from

50,000 barrels per acre to more than 1 million barrels per acre.

This formation contains, and depending on testimony this morning,

which numbers you look at, somewhere between 1 and 3 million

barrels per acre. That could equate to 2 to 3 trillion barrels of oil.

And as has been mentioned, that’s many more times than the total

reserves located in the Mideast.

In addition to oil shale, there are billions of barrels of tar sands

of oil in our area. The issues in regard to development of tar sands

mirror in many ways those of oil shale. We’re speaking primarily

of oil shale here today, but we have abundance of resource of both

commodities.

The majority of these resources are located on Federal lands

managed by the BLM. The remaining resources are located on that

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of the state and of private companies, individuals, and Indian

tribes.

In the ’70s and ’80s, there was considerable interest in the development of oil shale. Driven by gas shortages of the ’70s, the government, along with industry, put considerable resources into development of an oil shale facility in Uintah County, Utah. Local interest

in oil shale development did not decline when that of the general

government and industry did.

One company, in particular, has conducted resource and development activity since 1993. The results are the development of a

working retort that processes oil shale. This facility is currently attempting to obtain adequate feed stock to run their retort to enable

an independent certification of its operation.

Uintah County fully supports the development of oil shale and

tar sands. And one of the main points we would make is the mistakes of the past should not be repeated. The President and Department of Energy have determined that increasing liquid fuel

supply from domestic sources is an important national objective.

Clearly, there’s no greater opportunity to achieve this goal than the

development of the Nation’s oil shale resources.

Some of the benefits that would come from that, as we’re aware,

is it would bring the balance of trade closer in line; reduce the competition for energy resources with Third World countries and developing nations; stabilize American industry with a more dependable

fuel source; and provide the military with a source of fuel. Numerous byproducts could be produced.

We believe that there is immediate need for action. We believe

that government must play a critical role in removing impediments

to the development. I’m going to list several suggestions, though

this is in the testimony:

Authorize and direct the BLM to develop a commercial Federal

oil shale leasing program;

It’s been mentioned here this morning, but to repeal or modify

the Mineral Leasing Act that currently restricts oil shale leases to

one lease per company and a maximum 5,120 acres per lease,

which of course is eight sections;

Authorize and direct the BLM to exchange Federal lands for public or private lands, where appropriate, to facilitate development of

the resources;

Direct all of the Federal agencies to refrain from management

practices that restrict access to resource and prevent the development of these resources, including the water resources;

Authorize and direct the Department of Energy, in cooperation

with the BLM, to access and make available the existing White

River Mine, which was mentioned here earlier this morning, and

facilities, as well as oil shale stockpiles for use by industry;

This next point is a very important point to us in local government. Authorize the one-third of the total oil shale and tar sand

royalties to come back to the county of origin. This funding would

assist in mitigation of developing and maintaining social and economic impacts created with all energy-related development production;

All forms of transportation will be necessary;

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We are suggesting that at task force be created consisting of Fed- eral, state, and local government officials. Authorize this task force

to utilize expertise of industry, scientific, and collegiate academia.

Uintah County has considerable expertise and experience, and we

would like to be part of this resolution.

We would also like to, just as has been mentioned earlier here this morning, make an invitation to all members or any members

of this Committee or this Subcommittee or members of the

Resource Committee, to come out to our area and see what we have

out there. We would certainly host you. We would be happy for you

to come. And thank you for the opportunity to be here.

I might also just mention we provided a little bowl that has some

tar sands. That came from a mountain, or a hill about a couple of

miles just west of Vernal. And there are mountains of these tar

sands in our area.

This also is a piece of oil shale that came from the White River

Mine. If you were to break this oil shale open and were to smell

it, it would smell a little bit like diesel. But essentially, it’s algae.

Thank you very much.

[The prepared statement of Mr. McKee follows:]

Statement of Michael J. McKee, Commissioner,

Uintah County, Utah

OIL SHALE & TAR SANDS, UINTAH COUNTY, UTAH

I. A BRIEF HISTORY

In the ’70s and ’80s, there was considerable interest in the development of oil

shale. Driven by the gas shortage of the 70s the government, along with industry,

put considerable resources into the development of an oil shale facility in Uintah

County.

The decline in crude oil prices in the 80s resulted in the loss of government support for oil shale research and development, and subsequent termination of industry

interest.

All that remains of this effort is the White River Oil Shale Mine and associated

facilities in declining condition and oil shale stock piles.

II. WHERE WE ARE TODAY

A major portion of the oil shale resources of the Green River Formation are located in Uintah County. These resources are believed to be the most concentrated

accumulation of hydrocarbons on earth. The commercially attractive zones measure

from 50,000 barrels per acre to more than 1 million barrels per acre. The richness

of these zones are well known.

The majority of these resources are located on federal land managed by the BLM.

The remaining resources are owned by the state of Utah, individuals, private companies, and Indian tribes.

Because of the amount of resources existing under the federal lands, BLM

resource management on these lands will greatly affect their development.

Local interest in oil shale development did not decline when that of the general

government and industry did. One company, in particular, has conducted resource

and development activities since 1993. The results are the development of a working

retort that processes oil shale. This facility is currently attempting to obtain adequate feed stock to run their retort to enable an independent certification of its operation.

Uintah County fully supports the development of oil shale and is very concerned

that the mistakes made in past efforts should not be repeated. Specifically, the lack

of comprehensive and coordinate planning, impacts on community development and

local infrastructure were not properly planned for or funding needs considered.

III. POSSIBLE BENEFITS

The President and the Department of Energy have determined that increasing

liquid fuel supply from domestic sources is an important national objective. Clearly,

there is no greater opportunity to achieve this goal than the development of the

nation’s oil shale resources.

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The Green River formation located in our area contains three trillion tons of oil

shale, which is 2-3 times more than the reserves located in Saudi Arabia.

If these resources are developed, the United States could greatly reduce, and with conservation efforts, eliminate our dependency on imported oil and help reduce the

balance of trade.

Uintah County, the intermountain area, and the nation would benefit from oil shale development. As this development occurs, the following goals could be accomplished: • Keep the social and economic benefits of the $20 billion per month spent on imported oil and spend it on development in the United States. • Depending on the method used, there are numerous by-products that could be

produced. • Provide the military with a long term and secure source of fuel. • Stabilize American industry by having a more dependable fuel source. • Reduce global conflicts related to energy access. • Reduce the competition for energy resources with third world countries and developing nations.

IV. TAR SANDS DEVELOPMENT

In addition to oil shale Uintah County has considerable tar sands resources. There are billions of barrels of oil in the tar sands in our area. The issues in regards

to the development of tar sands in Uintah County mirror those for oil shale. Uintah County supports the development of tar sands, however, most of the com- ments in this document are on oil shale.

V. NEED FOR ACTION

Government must play a critical role in removing impediments to developments, and neutralizing and mitigating investment risk. Policies, regulations and legislation are needed to make these resources available on terms attractive to industry while ensuring efficient resource development and

equitable economic returns on investments. • Authorize and direct the BLM to develop a commercial Federal Oil Shale Leasing Program with the goal of initiating leasing by December 31, 2006. • Repeal or modify the Mineral Leasing Act that currently restricts oil shale

leases to one (1) lease per company and a maximum of 5,120 acres per lease. • Authorize and direct BLM to exchange Federal lands for public or private lands

where appropriate to facilitate development of the resource. • Direct all affected Federal Agencies within the confines of existing law, to refrain from management practices that restricts access to the resource and prevents the development of water resources needed for production and support infrastructure. • Authorize and direct the Department of Energy (DOE), in cooperation with

BLM, to access and make available the existing White River Mine and facilities,

as well as, oil shale stock piles for use by industry to support demonstration

and commercialization of oil shale technologies. • Authorize the return of 1/3 of the total oil shale and tar sand royalties to the

county of origin. This funding would assist in mitigation of developing and

maintaining social and economic impacts created with all energy related development and production. • All forms of transportation, including rights-of-way, roads, pipelines and other

means, are necessary to the success of oil shale development. There are immediate needs for transportation improvements during the research and development phase. Once production starts there will be a need to transport the materials out. It is imperative to have cooperation between Federal and State land

holders to allow access. • Existing delays in energy related development and production permit approvals

must be resolved to insure this problem doesn’t carry over into the processing

of oil shale leasing. Create a task force consisting of Federal, State and Local

government officials. Authorize this task force to utilize expertise of industry,

scientific and collegiate academia. Uintah County has considerable experience

and has access to expertise related to this issue and would like to be part of

the resolution. • Impacts to other resources such as wildlife, grazing, soil and water must be offset by improvement in existing habitats and/or carefully planned mitigation of

impacts.

Mitigating Investment Risks

Oil shale production is characterized by high capital and operating costs and long

periods of time between expenditure of capital funds and the realization of

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production revenues. For ‘‘first-generation’’ facilities there is substantial uncertainty

over the magnitude of capital and operating cost. Revenue uncertainty is imposed

by not knowing future market prices. These and other uncertainties pose investment

risks that currently make oil shale investment less attractive than other investment

options.

Public policy and legislation can lower investment risk by reducing cost and revenue uncertainties and by sharing in the financial risks. Public action is warranted

when pursuing public goals of secure domestic fuel supplies and enhanced business

and economic activity. The most effective of these actions include:

Demonstration Projects. A cost-shared oil shale demonstration program would:

• Accelerate the timetable to the all-important first-generation commercial production by helping to remove cost uncertainty,

• Broaden the base of investment interest among intermediate and independent

producers that could not carry the development risks alone, and

• Serve as evidence of the public’s commitment to this resource.

Market Assurance: Authorize and direct the Department of Defense to specify and

qualify shale oil derived aviation turbine fuels and to enter into purchase agreements at a guaranteed minimum and maximum price. This will serve to minimize

market-acceptance risk and price-volatility risk.

Production Tax Credit: A production tax credit, indexed to inflation and capped

or phased out at a ceiling price per barrel will enable oil shale to directly compete

with foreign conventional oil. This could be accomplished by amending current ‘‘Section 29’’ tax credits for non-conventional fuels or through a new provision crafted

for oil shale.

Federal Royalty Relief: Federal royalty structure is not yet defined for oil shale

extraction. Providing royalty relief in the research and development stages will significantly improve project economics. A fair return to the Federal government can

be achieved by graduated royalty rates in later years, after investment payback.

Accelerated Depreciation: Allowing front end capital investments to be depreciated

in a shorter time than is allowed under current law could improve cash flow and

could stimulate investment by enabling earlier payback. Royalty holidays and expended depreciation are credited as the two most important fiscal measures stimulating the production growth of Alberta oil sands.

Investment Tax Credit: Congress should allow an investment tax credit similar

to that which is proposed for coal-to-liquids projects to reduce up-front capital costs

and accelerate payback.

Depletion Allowance: Congress should allow oil shale projects to qualify for a percentage depletion allowance (similar to that for oil and gas resource extraction).

This latter provision helps provide parity for private resource holders relative to the

royalty holidays afforded federal lessees.

Community Development and Infrastructure Support

Oil shale industry development and operation will cause significant population

growth in the local communities, accompanied by requirements for investment in

community infrastructure, such as roads, schools, hospitals, and other support services. Uintah County is a water short area. Adequate water supplies must be developed for both domestic and industrial use.

Costs for engaging in the federal planning process and for planning and construction of infrastructure occur long before tax and royalty revenues are received from

oil shale operations and associated economic activity. Development delays or industry failure pose additional risks to local communities. Planning must include a strategy to avoid boom/bust cycles in local economy.

To minimize the severity of impacts and mitigate the financial risks the following

action is recommended:

• Authorize and direct the DOE, in cooperation with DOI and DOD, to develop

a well-conceived federal Oil Shale Program so as to avoid a crisis-oriented response,

• Communicate with stakeholders to identify issues of concern and take measures

to mitigate those concerns,

• Provide advance financial support for the communities and States to facilitate

their engagement in the program development process and to mitigate cost burdens that occur before tax and royalty revenues are realized.

Streamline Regulatory Permitting

Environmental impacts must be effectively mitigated through best-available

resource technologies and rigorous management utilizing adaptable and goal oriented management, not exclusionary management that is not practiced. Control of

air emissions, water effluents, leachates from spent shale disposal, land reclamation

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design, and other environmental issues will need to meet published regulatory

standards.

• Complying with these standards will require complete and comprehensive applications which should receive prompt review and action.

• Consistent with Executive Order 13212 ‘‘Actions to Expedite Energy Related

Projects’’, it is recommended that the Interagency Task Force be reconvened

and directed to coordinate with the EPA and state regulatory agencies and to

review Federal environmental requirements that impact oil shale development

and identify areas where permitting can be streamlined to achieve national

energy goals. To date, the provisions of this executive order have not been implemented at the field office level or reflected in the recent resource plan.

Government/Industry Coordination

• Development and implementation of a well-considered and coordinated Oil

Shale Program Plan requires goal-oriented management in government. To

complement the short-term insurance policy provided by the Strategic Petroleum Reserve Congress should authorize and direct the Secretary of Energy to

establish an Office of Strategic Fuels within the DOE Petroleum Reserves.

• The mission of this Office is to promote fuels security for the United States, provide the analytical basis for strategic fuels planning, oil shale program development and management, establish and administer functions of an interagency

government/industry oil shale task force and manage outreach and education efforts related to Federal oil shale efforts. The charter for this office should include interaction with the Departments of Defense, Interior, and Treasury.

• Congress should authorize and direct DOE to establish a Federal Oil Shale

Task Force, to include representatives from DOE, DOD, DOI, and the Department of Treasury, technical experts, and advisors from industry, impacted

states and communities, and other stakeholders to coordinate and facilitate oil

shale industry development efforts in an integrated fashion.

VI. PROPOSED OIL SHALE, RESEARCH, DEVELOPMENT AND DOCUMENTATION (RD&D) PROGRAM

In the supplementary information provided in the RD&D Program draft, it says

that BLM intends to ensure that states and local communities have the opportunity

to be involved in the development of a commercial program. Uintah County would

like to see this involvement extended to include all NEPA and mitigation and mitigation issues associated with both RD&D and commercial development.

In earlier comments Uintah County expressed concern regarding the adequacy of

40 acres to conduct RD&D operations. In the latest draft the 40 acres has been

changed to 160 acres. The County’s recommendation remains 640 acres.

BLM considers 160 acres adequate to accommodate an R&P activity that can be

envisioned. The County proposed 640 acres so as not to limit the type of R&D that

can be located on the site. Perhaps 160 acres could be established as a limit unless

the proponent can, based on development plans, justify additional acreage not to exceed 640 acres.

Response to questions submitted for the record by Michael J. McKee,

Commissioner, Uintah County, Utah

1. What are the most important things that the Federal Government can do to ensure

that production of large quantities of oil from oil shale happens in a timely manner and under appropriate conditions?

Response: There are several ways to ensure production of large quantities of oil

from oil shale in a timely and appropriate manner. They are:

• Develop a national policy and strategic plans that recognizes oil shale development as a way to reduce our dependence on imported oil that provides for it’s

development in a coordinated manner and fully involving local governments and

in recognition of the impacts of the development on them.

• Establish regulation for the commercial development of oil shale and expedite

access to oil shale resources.

• Structure royalties and provide tax incentives that will allow lessee to accelerate recoupment of investment so as to encourage rapid development.

• Use planning method similar to that used by the National Petroleum Reserve

to provide orderly and coordinate planning that will insure impacts to local communities are addressed and that infrastructure needs are well planned and

such projects are in place prior to onset of development. There is a need to implement the planning process now.

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2. We note Uintah County’s full support of oil shale development. Does the State of Utah have policies in place that you feel will provide Uintah County with it’s appropriate share of revenues, including royalties and severance taxes, that will be

derived from oil shale production? Do you feel that counties in which production

is located should receive a direct portion of the royalties and bonus bids?

Response: Utah does have policies in place for revenue sharing. However, polit- ical demographics prevent the counties of origin from receiving a proper share that

adequately reflects impacts to infrastructure and governmental services. While

County’s such as Uintah create the majority of the mineral revenues for the State

of Utah the portion of revenues return to the County is not reflective of that contribution. Uintah County strongly supports counties of origin receiving directly portions of revenues from development of natural resources on public lands within their

jurisdiction. In previous testimony Uintah County has supported the return of 1/3

(one third) of total royalties generated and bonus receipts to the county of origin

to offset cost of increased services, development of and improvements to infrastructure and impacts to the community.

3. Should the State of Utah, and it’s counties, set up a joint process with the BLM to coordinate and speed leasing and permitting decisions?

Response: Yes. Uintah County has considerable expertise in this issue and has for some time been active in leasing and permitting process on federal land through

cooperation and coordination of NEPA processes and by facilitating dialog on current leasing and permits back logs and addressing the issues of uncertainty in the

lease and permitting process. The County has actively sought additional funds to

provide adequate staffing in the local BLM office. The funding and staffing needed for a county to participate in these activities has put a burden on county resources which with the onset of oil shale development are

sure to increase. Compensation for increases in governmental service associated

with the increase in activity will help leasing and permitting decisions. It is imperative that the Bureau of Land Management office is funded adequately for such activities.

4. What can the federal government do to ensure that local communities have the up-front financial resources needed to plan for development and mitigate impacts?

Is there an immediate need?

Response: Uintah County recognizes the immediate need for up front cost for planning and development and to mitigate impact. The County is supportive of the

suggestions made by Jim Evans (in Russ George’s testimony to the Senate Energy

Subcommittee) that allocates current royalties produced from NOSR lands to this

effort. We also feel that an additional portion of mineral lease revenue (now expanding because of regional gas production) could be allocated to the Counties of Origin. The use of these funds provides immediate access to needed funds and would be

recouped by increased revenue from oil shale development.

Mr. GIBBONS. Mr. McKee, thank you very much for your testi- mony. Thank you for the visual aides that you provided, as well.

Thank you for your suggestions about how we should work together

in incorporating the stakeholders, local government, county governments, as well.

And again, Mr. George, your requests certainly are agreed upon, that we need to approach this with the full understanding that we

have to do it sensibly and correctly, considering the environmental

concerns that we all have in this certainly. We have two votes that have been called. We have about ten

minutes or less remaining. I am going to turn questions over to our

two panelists here, so that we might be able to wrap this up; because when we go to vote, who knows when we will get back. I

don’t want to hold you and this hearing open. Mrs. Drake, do you have any questions?

Mrs. DRAKE. Thank you. And I will be real quick, because I am

sure we will submit other questions to you. Does this type of

resource exist in China? I am sure you probably saw that article

today about China doing an unsolicited bid to take over one of our

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oil companies, an $18-1/2 billion bid. I think we are all concerned

about China. But does this type of resource exist in China, that if

this technology is developed here, maybe they would be able to

meet their own needs there? It is completely off the subject, but it

is a thing that hit my mind.

Mr. MCKEE. There are others that certainly would know the geology of this better than what I do. But I do know that the Green

River formation located in eastern Utah, western Colorado, and

southern Wyoming, is the best resource in the world, by far. And

while there may be resources, and I’m sure there are, in many

other parts of the world, we have the best resource.

Mrs. DRAKE. And I would assume both of you would agree that

this is not a shaky industry or shaky research or a shaky resource

for us to develop, like we heard earlier?

Mr. MCKEE. We believe that this actually is around the corner.

We believe that, with some help, if we can remove some of these

impediments—there may need to be some tax credits. It depends

on how fast we want to move along with this, in my estimation.

If we want to kind of just go along the way we’re going, it’s going

to take longer. If we want to streamline the process, I believe with

some tax credits and some things up front, that it will expedite and

help this to happen in more rapid fashion than it will naturally.

Mrs. DRAKE. I would like to thank both of your states for being

visionaries. Thank you.

Mr. GEORGE. May I respond to your last comment? Have I got

just a minute to do that? I was born and raised in the shadow of

oil shale in western Colorado. And growing up, we heard about

‘‘Boom-bust, oil shale will never happen.’’ Oil shale has chemistry

to it that matters for human uses. So it will become a source of hydrocarbons for a number of uses, as time occurs.

What Colorado would like to suggest is that we should not have

stopped research and development with the last bust 20 years ago.

We have made virtually no progress on the science and the technology in the last 20 years. What we don’t think would be wise is

for us to have our successors come back here in 20 years and say

again what I have just said.

We need to get on with it. We can do it. We can see how to do

it. Our friends to the north in Alberta have shown us a way. And

we need to get on about doing it ourselves.

Mrs. DRAKE. Thank you very much.

Mr. GIBBONS. Thank you very much. And to our witnesses, both

of you, I apologize for the fact that we do not control the schedule

on the Floor. They vote when they want to vote and set those in

accordance. And sometimes they interfere with the great work that

we are doing on these committees.

Your testimony, your presence here today, has been absolutely

very valuable. Let us hope that we on the Federal side when we

develop our policies can work with the county governments, state

governments, that have these resources within their borders, to formulate expedited processes with regard to permitting, etcetera, so

that we do it uniformly; that we do it without a lot of delay and

bureaucratic obfuscation, if you will; so that we can get to this

resource that is so vitally critical to the economy of this country.

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I do appreciate the fact that each of you have taken a great deal

of your time to come here today. We will submit written questions

that we would like to ask for each of the panels to respond to accordingly and report back their answers to us; probably within a

ten-day timeframe, if you could.

With that, again, I want to thank each and every one of you;

apologizing for the interruption of our hearing today with the votes

on the Floor. And again, your testimony has been critical to a better understanding. This is part one of a two-part hearing series.

And we certainly look forward to future information and, as I said,

to a brighter future with an energy policy that takes in oil sands,

oil shales, and heavy oil, and unconventional sources.

With that, this hearing is adjourned. Thank you very much.

Mr. GEORGE. Thank you, Mr. Chairman.

Mr. MCKEE. Thank you.

[Whereupon, at 11:45 a.m., the Subcommittee was adjourned.]

[Additional material submitted for the record follows:]

[A statement submitted for the record by the Department of

Energy, Government of Alberta, Canada, follows:]

Statement submitted for the record by the Department of Energy,

Government of Alberta, Canada, 14th Floor, North Petroleum Plaza,

9945 - 108th Street, Edmonton, Alberta Canada T2K 2G8, http://

www.energy.gov.ab.ca/89.asp

The Government of Alberta, Canada, is pleased to provide this written submission

on the Alberta Oil Sands to the U.S. Subcommittee on Energy and Mineral

Resources.

Included herein is a brief overview of the Province of Alberta; our role in North

American energy security; the extent of oil sands resources in Alberta including reserves based on currently available extraction technologies; the role the Government

of Alberta plays in bringing these valuable resources to market; and, importantly,

the direct effect this has had on increasing investment and production. Production

of crude oil from Alberta’s oil sands has the potential to close the U.S. energy gap.

The Province of Alberta

Albertans are a breed apart. They are driven by the pioneering spirit that first

settled the land. They hold dear the ethics of hard work and personal responsibility.

They cherish the ideals of family and community that built the province.

Our policies focus on free trade and competitive markets as the best way to allocate scarce resources. Provincial law prevents the government from subsidizing any

commercial business entity. The Province has no sales tax, a 10% flat personal income tax, and no debt—something that has not been achieved anywhere else in

Canada, and something of which Albertans are justifiably proud.

Year after year, Alberta’s economic growth leads Canada, averaging 3.7% annually over the past 10 years. We lead the nation in job creation, and our unemployment rate is consistently among the lowest in Canada. Alberta’s per capita disposable income and standard of living are the highest in Canada. Not surprisingly, we

continue to experience the strongest population growth in Canada, with people from

all over Canada and around the world migrating to our province to experience the

Alberta Advantage for themselves and their families.

North American Energy Security

Alberta is rich in hydrocarbon resources—producing almost 1.7 million barrels per

day of crude oil, and 13.8 billion cubic feet per day of natural gas.

Both Alberta and Canada are vital to the energy security of the United States—

we are reliable, secure and, importantly, stable suppliers of energy to the US. In

2004, for the sixth year running, the U.S. Energy Information Administration recognized Canada as the largest supplier of oil (crude and refined) to the US.

Approximately 12% of U.S. crude oil imports and 11% of its natural gas consumption come from Alberta alone.

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What are oil sands?

Oil sands are deposits of bitumen, a molasses-like viscous oil that requires heating or dilution with lighter hydrocarbons in order to flow. Second only to the Saudi

Arabian reserves, Alberta’s oil sands deposits have been described by Time Magazine as ‘‘Canada’s greatest buried energy treasure,’’ which ‘‘could satisfy the world’s

demand for petroleum for the next century.’’

Deposits are found in three major areas in northeastern Alberta: Peace River,

Athabasca (Fort McMurray area), and Cold Lake (north of Lloydminster), totaling

approximately 54,400 square miles—an area larger than the state of Florida.

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Size of Alberta Oil Sands Reserves

Alberta is home to the largest oil sands reserves in the world. Established reserves of 174.5 billion barrels are second only to Saudi Arabia reserves.

This data is on the public record and confirmed by the Alberta Energy & Utilities

Board (AEUB), an arms-length regulatory agency. Over 56,000 wells and 6,000 cores

were the basis of the analysis.

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Since December 2002, these figures were recognized by the Oil & Gas Journal,

followed by the U.S. Energy Information Administration in 2003.

Growth in Oil Sands Production

Oil sands raw bitumen production in Alberta averaged close to 1.1 million barrels

a day in 2004 (about one-third of total Canadian production). By the end of this decade, we expect production to rise to 2 million barrels a day. See Appendix 1: Oil

Sands potential: 3 million bpd by 2020, 5 million bpd by 2030.

Annual oil sands production is growing steadily by about 200-250 barrels per day

(bbl/d) per year, as the industry matures. Output of marketable production increased to 962,000 bbl/d in 2004 from 853,000 bbl/d in 2003. It is anticipated that

in 2005, Alberta’s oil sands production may account for one-half of Canada’s total

crude output and 10 per cent of North American production.

Production Methods: Mining and In-Situ

There are two methods of oil sands production methods: mining and in-situ. Oil

sands mining involves open pit operations. Oil sands are moved by trucks and shovels to a cleaning facility where the material is mixed with warm water to remove

the bitumen from the sand. Today, all operating oil sands mines are linked with

upgraders that convert the bitumen to synthetic crude oil.

For oil sands reservoirs too deep to support economic surface mining operations,

some form of an in-situ or ‘‘in place’’ recovery is required to produce bitumen. Insitu oil sands production is similar to that of conventional oil production where oil

is recovered through wells. Present operating costs, not including capital recovery,

vary between $10-15/per barrel.

The AEUB estimates that 80% of the total bitumen ultimately recoverable will be

with in-situ techniques. In general, the heavy, viscous nature of the bitumen means

that it will not flow under normal conditions. Numerous in-situ technologies have

been developed that apply thermal energy to heat the bitumen and allow it to flow

to the well bore. These include thermal (steam) injection through vertical or horizontal wells such as cyclic steam stimulation (CSS), pressure cyclic steam drive

(PCSD) and steam assisted gravity drainage (SAGD). Other technologies are emerging such as pulse technology, vapor recovery extraction (VAPEX) and toe-to-heel air

injection (THAI).

In general, oil sands mines operations are found in central Athabasca deposits

(around Fort McMurray). In-situ production is used in the Cold Lake, south Athabasca and Peace River deposits.

Government Framework

The mineral rights in approximately 97% of Alberta’s 54,000 square miles of oil

sands area are owned by the Government of Alberta (i.e., state-level) and managed

by the Alberta Department of Energy. The remaining 3% of the oil sands mineral

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rights in the province are held by the federal Government of Canada (i.e., federallevel) within First Nation reserves, by successors in title to the Hudson’s Bay Company, by the national railway companies and by the descendents of original homesteaders through rights granted by the Government of Canada before 1887. These

rights are referred to as ‘‘freehold rights’’.

The Alberta government departments of Environment and Sustainable Resource

Development administer complementary environmental policies. The Alberta Energy

& Utilities Board (AEUB) regulates oil and gas activities in the province.

The Alberta Department of Energy is responsible for administering the legislation

that governs the ownership, royalty and administration of Alberta’s oil, gas, oil

sands, coal, metallic and other mineral resources. The Department’s main objective

is to manage these non-renewable resources to ensure their efficient development

for the greatest possible benefit to the province and its people.

Oil Sands Royalty Structure

In 1996, Alberta announced a new generic royalty regime for oil sands based on

recommendations from a joint industry/government National Oil Sands Task Force

(NOSTF). This regime is defined in the Mines and Minerals Act and the Oil Sands

Royalty Regulation 1997, as amended (OSRR 97). Royalty is calculated using a revenue-less-cost calculation.

In early project years before capital investment and other costs are recovered, the

royalty rate is lower than the rate that is applied after costs are recovered. This

helps project cash flows in early years. Once costs are recovered, the Province

shares in project profits. Details are provided below.

• In the pre-payout period (before the project has recovered all of its costs),

projects pay royalty tied to 1% of gross revenue;

• In the post-payout period (after the project has recovered all of its costs),

projects pay royalty tied to the greater of 1% of gross revenue or 25% of net

revenue.

Since 1990, oil sands royalties have totaled over $2.5 billion.

Announced Investment

Since 1996, when the generic royalty regime was introduced, an estimated $35 billion of investment in the oil sands has occurred. Looking forward, it is expected that

new capital investment could range from $2.5-$4 billion per year.

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The Way Forward

To date, only about 2% of the established oil sands resource has been produced.

Alberta’s oil sands industry is the result of multi-billion-dollar investments in infrastructure and technology required to develop the non-conventional resource. In the

last five years alone, industry has allocated an estimated $28 billion towards oil

sands development, and the Government of Alberta invested over $700 million over

a 20-year period.

Alberta encourages the responsible development of these extensive deposits

through planning and liaison among government, industry and communities to ensure a competitive royalty regime that is attractive to investors, appropriate regulations and environmental protection and the management of the Province of Alberta’s

rights to oil sands while taking into account some of the barriers—higher technological risk and higher capital costs—faced by oil sands developers.

In 2004, Alberta’s oil sands were the source of over half of the province’s total

crude oil and equivalent production and over one third of all crude oil and equivalent produced in Canada. Over the last three fiscal years, through to 2003/2004, oil

sands development returned $565 million to Albertans in the form of royalties paid

to the Provincial government.

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Continuing technology improvements will lead to greater energy efficiency and a reduction in natural gas as a fuel input source. As the future unfolds, the only impediment to oil sands production could be shortages of skilled labour to complete

the projects. Oil sands projects will compete for the same skilled workforce as the

Mackenzie and Alaska natural gas pipelines. Development of Alberta’s oil sands resources represents a triumph of technological innovation. Over the years, government and industry have worked together to find

innovative and economic ways to extract and process the oil sands and energy research is more important today than ever before. Working through the Alberta

Energy Research Institute, the Alberta government is committed to a collaborative

approach with counterparts in Canada and the United States to spur new technology and innovation programs that will reduce the impact of greenhouse gases

and other emissions, and reduce the consumption of water and gas.

[A statement submitted for the record by Mark Mathis, Executive Director, Citizens’ Alliance for Responsible Energy,

follows:]

Statement of Mark Mathis, Executive Director,

Citizens’ Alliance for Responsible Energy

My name is Mark Mathis. My address is 8419 Vina Del Sol Dr. NE, Albuquerque,

NM 87122. I am a former television news reporter and anchor. I’ve been a media

consultant for the past eleven years. Two and a half years ago I began consulting

with the Independent Petroleum Association of New Mexico. It took only a short period of time for me to understand the great frustration endured by energy producers. They are under constant attack by anti-development groups posing as environmentalists. Much of the time the accusations and rhetoric dispensed by these

groups is greatly distorted if not entirely false. Within a year’s time I could see that

something needed to be done. It was at that time that I began contemplating starting a non-profit organization for the purpose of educating the public about energy

issues. I believe a better-informed public will result in government leaders making

better decisions concerning our national energy policy. I have some experience in

standing up for the public. In 2001, I formed an organization called ‘‘The 505 Coalition’’ to fight a new and unnecessary area code from being implemented in New

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Mexico. As a result of the efforts of the 505 Coalition rulings by the federal and

state governments were rescinded, saving an estimated $50 million in public and

private funds. I wish to apply that same type of activism to the critical task of safeguarding our nation’s energy supply.

The Wildlands Project

To date, the most comprehensive environmental coalition to appear on the scene

is the Wildlands Project. This coalition is the most radical in purpose: to ‘‘re-wild’’

America, that is, to gradually remove people and raw material production from the

rural United States with no definite stopping point. In their own words: 1

‘‘The Wildlands Project calls for reserves established to protect wild habitat, biodiversity, ecological integrity, ecological services, and evolutionary processes. In

other words, vast interconnected areas of true wilderness and wild lands. We reject

the notion that wilderness is merely remote, scenic terrain suitable for backpacking.

Rather, we see wilderness as the home for unfettered life, free from human technological and industrial intervention.’’

‘‘Extensive roadless areas of native vegetation in various successional stages must

be off-limits to human exploitation.’’

‘‘To function properly, nature needs vast landscapes without roads, dams, motorized vehicles, power lines, over-flights, or other artifacts of civilization, where evolutionary and ecological processes can continue. Such wildlands are absolutely essential to protect biodiversity.’’

The Wildlands Project has proposed to set aside at least half of North America

for ‘‘the preservation of biological diversity.’’ The resulting ‘‘wildland reserves’’ would

contain:

• Cores, created from public lands such as national forests and parks, allowing

for little, if any, human use

• Buffers, created from private land adjoining the cores to provide additional protection;

• Corridors, a mix of public and private lands usually following along rivers and

wildlife migration routes;

but would allow no cities, roads, homes, businesses, no aircraft over-flights, or natural resource extraction, i.e., an ever expanding area of America would be depopulated and de-developed.

A decade ago such proposals would not have been taken seriously. Even today this

kind of proposal would seem highly unrealistic to a lot of people. However, such

grand visions are not accomplished over night. They happen incrementally. Even

though the term ‘‘Wildlands Project’’ is not widely known, it still presents a formidable threat to private property ownership, mineral and resource extraction, and national security. Countless anti-development organizations are pursing the goals of

Wildlands without specifically using the term.

In the late 1990s, the Clinton Administration adopted aspects of The Wildlands

Project philosophy pushed largely by Vice President Al Gore. In Mr. Clinton’s term

we witnessed a moratorium on road construction in undeveloped areas. There were

proposals to breach dams on the Columbia River. The expansion of the Endangered

Species Act continued unabated.

The Wildlands Project is technically a coalition strategy project with a single lead

organization: North American Wilderness Recovery, Inc. (2000 revenue: $1,451,459),

originally based in Tucson, Arizona, but relocated in 2000 to Richmond, Vermont.

The organization is an outgrowth of a 1981 Earth First! idea called the North American Wilderness Recovery Project.

North American Wilderness Recovery has been supported by foundation grants

since before its exemption 1992, particularly by Doug Tompkins’ Foundation for

Deep Ecology, in annual amounts ranging from $50,000 in 1992 to $150,000 in 1996

and 1997. The Richard and Rhoda Goldman Fund gave $75,000 in 1996 and the

Educational Foundation of America gave $50,000 in 1997. 2

A Public Deceived

We have entered the great information age. Media is all around us in television,

radio, newspapers and magazines. We’ve got CDs, DVDs, MP3s, and satellite TV.

With our computers and the Internet massive amounts of information is just a few

mouse clicks away. We can learn about the most obscure subject in great depth

without ever leaving our homes. And yet, in the midst of this sea of information,

many Americans are either ignorant or misinformed about some the most fundamentally important issues to their lives. This is the great irony of the 21st Century. We don’t live in the information age. We live in the age of disinformation.

I believe the most critical and misunderstood issue of our time is the balance between energy development and the environment. We all know we need energy for

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our daily lives—electricity for lights, appliances, computers and hundreds of other

devises. We know we need gasoline for our cars, jet fuel for airplanes, diesel for big

trucks and ships and all kinds of other fuels such as propane and butane. We depend on this energy for absolutely everything, and yet hardly ever think about

where this life-sustaining power comes from. While Americans sit in their comfortable homes with every conceivable necessity and luxury they watch the morning news. There’s another protest about ‘‘environmental destruction’’ caused by fossil fuels. Then they read a newspaper story about

the rapid and catastrophic loss of endangered species. Then it’s off to work where

a radio ad informs them that some ‘‘pristine’’ wilderness is about to be destroyed

by oil and natural gas development. While cruising along the highway they see a

billboard warning them of the dangers of nuclear power. They press on the gas, take

a swig of bottled water and shake their heads at those awful energy companies that

are ruining their lives. From every direction Americans are being fed a litany of lies and distortions. As preposterous as it is, people have been trained to despise the energy sources that

are the foundation of unprecedented health, longevity and prosperity. Americans

have been fed so much disinformation for so long that they no longer trust their

own experience. They just assume the disinformation is true and those assumptions

are rarely if ever challenged. Because the public is so misinformed, a relatively small number of people who participate in vocal, well organized and very well funded activist groups are given

undue influence over public policy. They demand unreasonable regulations and restrictions on energy development and they get a lot of attention from the press. For example, The Wildlands Project and other activist groups claim we are in the ‘‘6th great extinction of species.’’ However, a 1995 United Nations report states that

there have never been so many species as there are in the modern era. 3

On The Wildlands Website, Stanford University professor Paul Ehrlich is quoted

as saying: Although the Wildlands Project’s call for restoring keystone species and

connectivity was met, at first, with amusement, these goals have now been

embraced broadly as the only realistic strategy for ending the extinction

crisis. 4

It’s surprising that The Wildlands Project would give Ehrlich such a prominent place on its website. Ehrlich is not so much famous as he is notorious for making

doomsday predictions that do not come true. In 1981 Ehrlich predicted that we

would lose 250,000 species every year. The widely discredited futurist claimed that

half of all species would be gone by the year 2000 and that all species would be

dead between 2010 and 2025. 5

True environmentalists, such as GreenPeace founder Patrick Moore, cite biological evidence that less than one percent of species may be lost in the next century.

Moore left GreenPeace many years ago because he said the environmental movement was ‘‘basically hijacked by political and social activists’’. Moore was interviewed for the segment ‘‘Environmental Hysteria’’ by Showtime’s Penn & Teller program. Moore told Penn & Teller that these phony environmentalists, ‘‘came in and

very cleverly learned how to use green rhetoric or green language to cloak agendas

that actually had more to do with anti-corporatism, anti-globalization, anti-business

and very little to do with science or ecology.’’ 6

The Wildlands Project and other groups that support the same anti-development

agenda are effective in spreading disinformation through their skill in using the

news media. They know that they can make outrageous claims and the chance that

those claims will actually be challenged is very small. They know that journalists

typically don’t know enough about these complex issues to even ask the right questions, let alone to challenge the sensational assumptions. Reporters are not given

enough time or resources to do more than simply repeat the activists’ claims. Of

course, some reporters are believers in the obstructionist movement and their bias

heavily influences their stories. But more than anything, the press cannot resist

emotional, sensational, fear-based claims. It’s their bread and butter in the 21st century.

Journalistic arrogance, of course, is another problem. Syndicated columnist Stanley Crouch recently informed readers of The New York Daily News, ‘‘The recent congressional vote for Arctic drilling would not have been necessary if we had maintained commitment to developing nuclear power as an energy source.’’ It apparently

didn’t occur to Mr. Crouch that there’s no such thing as a nuclear-powered car, tractor-trailer or airplane. 7

I have considerable knowledge in this area of media manipulation. I was a news

reporter for nine years in four states and I’ve been a media consultant for more than

11 years. In my book, Feeding the Media Beast, I devote a chapter to ‘‘The Rule

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of Emotion’’ and another to ‘‘The Rule of Repetition’’. Anti-development groups are

very good at using these powerful rules to their advantage. 8

The Renewable Deception

Supporters of the Wildlands Project philosophy are big supporters of renewable

energy sources such as wind, solar, and biomass. They continually urge the public

and government leaders to reject fossil fuels and to embrace the energy sources of

the 21st century. These kinds of politically correct statements receive broad approval because they sound so good. However, the fact is renewable energy sources

running our world is nothing more than pure fantasy for at least several more decades and probably longer. 9

Professional obstructionists and even some politicians have led people believe that

a greater investment in wind and solar power will somehow make us less dependent

on foreign oil. That’s ridiculous. Wind turbines and solar panels generate electricity,

which does nothing to replace the oil that fuels virtually all forms of transportation.

Even the electricity generation of wind and solar power is minuscule at this point,

contributing less than one half of one percent to our electricity needs. 10

To the uninformed, this distinction may seem trivial. In reality its importance

couldn’t be greater. We don’t have an electricity problem in this country (though we

could use more power plants and an upgraded grid); we have a deadly serious liquid

fuels crisis that threatens our economy, our national security and indeed all that

we hold dear.

There are other groups such as the Energy Future Coalition and The Governors’

Ethanol Coalition made up of governors from 33 states. These organizations want

Congress to increase a federally mandated use of ethanol above the 5 billion gallons

required by 2012. 11 These governors score points—and votes—by appearing to actually be doing something about our thirst for foreign oil and desire to have a cleaner

environment. Farm belt governors score double points because 95% of ethanol is

made from corn.

However, this is just another energy deception. It takes more fuel to produce and

deliver ethanol than it provides, meaning we import more foreign oil, not less. While

ethanol is advertised as burning cleaner than gasoline, on balance it actually produces more and worse pollution. Ethanol emits higher levels of NOx emissions contributing to smog, and it makes gasoline evaporate faster, reducing its value while

increasing pollution. It also must be shipped separately and mixed at distribution

terminals, which simultaneously drives up costs, fuel usage and emissions. 12

The Big Hammer: The Endangered Species Act

No single tool has been more effective in advancing the goals of The Wildlands

Project than the Endangered Species Act. Say ‘‘Endangered Species Act’’ and most

Americans believe this is a federal law that protects species in danger of becoming

extinct. While that was the original intent, today the Act has very little to do with

protecting species in trouble. It is a simply a tool for anti-development groups posing

as environmentalists to shut down any and all uses of public land, energy development being number one on the list.

One of the fundamental flaws of the ESA is that species do not recognize state

boundaries. If a species is determined to be ‘‘endangered’’ in one state it may become

listed as such even though an abundance of the species exist in other parts of the

country or in other nations. For example, the Aplomado Falcon is listed as endangered in New Mexico when the species hasn’t even existed in the state for the past

half century. 13 The Bureau of Land Management has restricted energy development

on 36,000 acres on Otero Mesa just in case the falcon decides to come back. Even

worse, the falcon can be found in great abundance on the entire continent of South

America, throughout Central America, all of Mexico, and into Texas. 14 An additional

88,000 acres on Otero Mesa are off-limits for other conservation concerns. Dozens

upon dozens of cases such as this can be found all across the country.

Another big problem is that once a species is listed it is extraordinarily difficult

to get it de-listed. In the 32-year history of the ESA only 10 species have been removed from the endangered list because of ‘‘recovery’’. Even then, critics charge that

some of those species were saved by private efforts and other activities such the

banning of DDT.

In New Mexico the Gila Trout was first listed as endangered in 1967. The U.S.

Fish & Wildlife Service proposed downgrading it to threatened in 1987 but under

pressure withdrew the proposal. Another request came in 1996. It didn’t happen.

Today the USFW is attempting a third time but is running into stiff objections from

anti-development groups. 15

Enforcing the ESA is very expensive to taxpayers as well as private property owners. In the west, the U.S. Fish and Wildlife Service estimates it will cost about $30

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million to $40 million every year to protect the endangered southwestern willow

flycatcher. Unfortunately, this kind of outrageous expense for species protection is

the rule rather than the exception. Remember, there are 1,262 Endangered Species

and obstructionists are filing lawsuits and lobbying hard to have more added all the

time.

There are many other flaws in the Endangered Species Act such as the fact that

in many cases access to land is restricted based on the ‘‘Best Available Data’’, which

often stands for ‘‘BAD’’ data because data are incomplete and sometimes non-existent. Another flaw is the fact that private landowners lose use of their land because

of an endangered species and they receive no compensation from the government.

There are more problems, however the intent of this testimony is not to make suggestions on how to fix the ESA, but simply to point out that the Act is highly flawed

and yet very powerful in restricting access to land for all purposes, most importantly

to energy development.

Energy is Everything

It is almost impossible to overstate the importance of oil and its powerful brother,

natural gas. Without them our world would be completely different, more different

than any of us can possibly imagine.

Look around you and try to spot a single item that would still be there if oil were

not. When people think of oil and natural gas they typically consider its obvious

uses’gasoline for the car, a lubricant for the engine, and a power source for electricity generation and the heating of homes. What about rubber for tires, shoes, and

seals on refrigerators, ovens, and car doors? Consider the importance of asphalt, fertilizers, pesticides, and glue. What would life be like without magic markers, lipstick, pantyhose, credit cards, dental floss, toothpaste, baby bottles, telephones, TVs,

computers, soccer balls, paint, and synthetic fibers for today’s clothing?

The vast quantity of everyday items that contain some byproduct of petroleum is

astonishing. Take these products away and our world would come to a sudden and

catastrophic end. If somehow we could instantly remove the contribution of petroleum to our world you would find yourself standing naked and unsheltered in an

open landscape among millions of other naked and unsheltered souls.

It’s a little unnerving just to think about it. There’s only one thing more important to our survival than oil and natural gas, and that’s oxygen. Yes, water, food,

clothing, and shelter are essential, but in today’s world the vast majority of the population cannot get these life-sustaining necessities without petroleum.

Yet, in spite of these sobering realities, a misinformed public stands by while access to oil and natural gas are denied under the pretense of ‘‘environmental protection.’’

Oil & National Defense: A Sobering Reality

Oil—as well as all other energy sources—is directly tied to the success and survival of the United States of America. The same can be said of any other country.

Fundamentally, no society can endure—let alone prosper—without two things: an

adequate and affordable food supply and the availability of affordable energy. Because our food supply is almost completely dependent on oil, petroleum is the most

important commodity we have.

While it’s quite clear that our economy and standard of living are completely dependent upon oil, it may be less clear that petroleum is a key ingredient in our freedom, too. Without adequate fuel supplies for fighter jets, battleships, tanks and

other armored vehicles America would be vulnerable to any nation that wished to

take what we have as their own, and that includes our liberty as well.

Allied forces defeated the Axis powers in World War II for a variety of reasons—

brave men and women, intelligent military leaders, and a home-front that made

great sacrifices to give the military all that it needed while still running a nation.

However, no level of bravery or sacrifice would have mattered if the United States

hadn’t had sufficient oil supplies to fuel victory.

Freedom isn’t free. It takes enormous sums of bravery, skill, passion, human ingenuity and the fuel to make it all work.

A Promising Alternative: Oil Shale

One of the most promising alternatives to oil is what’s called ‘‘oil shale’’. The potential resource is enormous. It’s estimated that there is over 200 times more oil

shale than there are conventional reserves. Better yet, the United States is estimated to have 62% of the world’s potentially recoverable oil shale resources at 2 trillion barrels. According to The World Energy Council the largest of the deposits is

found in the 42,700 km2 Eocene Green River formation in north-western Colorado,

northeastern Utah and southwestern Wyoming. 16

80

The name is actually a misnomer because it does not contain oil and it is not

often found in shale. The organic material in oil shale is kerogen and it’s contained

in a hard rock called marl. When processed, kerogen can be converted into a substance similar to petroleum. During this process the organic material is liquefied

and processed into an oil-type substance. The quality of the product is typically better than the lowest grade of oil produced from conventional reserves.

Unfortunately, oil shale poses several significant problems. Processing of oil shale

requires significant amounts of energy and water. It also produces massive amounts

of waste product. In the 1970’s major oil companies in the U.S. spent billions of dollars in various unsuccessful attempts to commercially extract shale oil. However, as

the price of conventional oil rises the economics of shale oil will improve. When that

happens we can expect groups supporting The Wildlands Project philosophy to

mount a well-funded and well-organized protest. As always, disinformation will lead

their plan of attack.

A Difficult Task

Getting the American public and government leaders to focus on the critical importance of responsible domestic energy production is no easy task. Re-educating the

public about the nation’s true environmental condition will be even more difficult.

However, CARE was formed to address these issues because the stakes are extraordinarily high. The stability of our economy and the foundation of our national security are directly tied to our ability to produce domestic energy. It is bad public policy

to continue to become more dependent on foreign and often unstable governments

to fulfill our energy requirements, especially when environmentally responsible production is a reality today.

ENDNOTES

1 Ron Arnold, Undue Influence, Free Enterprise Press, 1999, p. 171-172;

www.twp.org, Internet Archive 1998 2 North American Wilderness Recovery, IRS form 990, 1993-1997; Foundation Center Database 3 Bjorn Lomborg, The Skeptical Environmentalist, Cambridge Press, 1988, p. 249;

United Nations Environment Programme 1995: 204, 206, 207 4The Wildlands Project Website: http://www.twp.org:80/cms/page1089.cfm

5Lomborg, The Skeptical Environmentalist, p. 249

6 ‘‘Penn & Teller BullShit,’’ Showtime Networks, ‘‘Environmental Hysteria’’

Season 1 7 Albuquerque Journal, April 1, 2005

8Mark Mathis, Feeding the Media Beast: An Easy Recipe for Great Publicity, Purdue University Press, May, 2002 9 Robert L. Bradley, Richard W. Fulmer, Energy: The Master Resource, p.185-186

Kendall Hunt Publishing Co. 2004 10 Energy Information Administration, U.S. Department of Energy, ‘‘Renewable

Energy Trends 2003’’, July 2004, p. 5 11 Energy Future Coalition, www.energyfuturecoalition.org; The Governors’ Ethanol

Coalition, www.ethanol-gec.org/Transmittal—Letter—to—White—House—pdf 12 Robert L. Bradley, Richard W. Fulmer, Energy: The Master Resource, p.57-58,

129-130, 131, 134-135, 162, Kendall Hunt Publishing Co. 2004 13The Peregrine Fund, www.peregrinefund.org, restoration projects page, Aplomado

Falcon 14The Peregrine Fund, www.peregrinefund.org/Explore—Raptors/falcons/

aplomado.html 15 Albuquerque Journal, May 18, 2005 16World Energy Council: www.worldenergy.org/wec-geis/publications/reports/ser/

shale/shale.asp

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OVERSIGHT HEARING ON ‘‘THE VAST NORTH

AMERICAN RESOURCE POTENTIAL OF OIL

SHALE, OIL SANDS, AND HEAVY OILS,’’

PART 2

Thursday, June 30, 2005

U.S. House of Representatives

Subcommittee on Energy and Mineral Resources

Committee on Resources

Washington, D.C.

The Subcommittee met, pursuant to notice, at 10:02 a.m., in

Room 1324, Longworth House Office Building, Hon. Jim Gibbons

[Chairman of the Subcommittee] presiding. Present: Representatives Cannon, Pearce, and Drake.

STATEMENT OF THE HON. JIM GIBBONS, A REPRESENTATIVE

IN CONGRESS FROM THE STATE OF NEVADA

Mr. GIBBONS. The Subcommittee on Energy and Mineral Resources will come to order.

Today’s hearing, entitled ‘‘The Vast North American Resource Potential of Oil Shale, Oil Sands, and Heavy Oils,’’ is Part Two of

a series of hearings. The Subcommittee today meets to hold its

second of those two-part hearings on this very subject.

STATEMENT OF HON. JIM GIBBONS, A REPRESENTATIVE IN

CONGRESS FROM THE STATE OF NEVADA

Mr. GIBBONS. At part one of this hearing, we focused on dispel- ling the myth that the United States has only three percent of the

world’s oil reserves. A report by the Department of Energy, that

can be found in the Subcommittee’s website, estimates that the

U.S. has two trillion barrels of oil shale, out of the 2.6 trillion barrels found worldwide. The domestic production possible from this

resource would be sufficient to replace all of the United States’ foreign oil imports except those from Canada and Mexico.

Also, at the first part of this hearing, this Subcommittee heard

from resource experts, resource producers, and state and local government representatives on a range of topics, with a focus on the

vast North American unconventional oil resource potential.

Witnesses discussed the feasibility of developing unconventional

oil resources through the lessons learned from the oil sands production in Alberta, Canada; as well as recommendations to facilitate

commercial leasing and production of oil from federally owned oil

82

shale. We learned that unconventional oil development is not only

feasible, but has the promise of delivering low-cost oil to consumers.

I was very encouraged by the enthusiasm for oil shale production at the last hearing, and look forward to hearing from officials from

the Departments of Defense, Energy, and Interior, on their view of

the Federal Government’s role in managing, utilizing, and facilitating production of these unconventional sources of oil. With approximately 70 percent of the land containing potential oil shale development being owned by the Federal Government, the

Federal Government will have a vital role in the facilitation of production. I believe the Government has a responsibility for development of these valuable resources, and this includes looking for

ways to remove barriers to production. As this Subcommittee has discussed in previous hearings, de- pendence on trans-oceanic energy imports is dangerous to our economic and national security. Despite promises from OPEC to increase production from member countries, oil prices have continued

their movement higher and higher. Recent projections show that oil

prices could reach more than $100 per barrel in the not-too-distant

future.

World oil supplies are growing tighter due to the inability of oil production to grow as fast as increases in oil demand; primarily because of increased demand from countries with rapidly growing

economies, such as China and India.

Global oil supplies are also strained because areas that would be

highly prospective for energy production are either off limits to

leasing, or the resources are not otherwise being made available for

leasing; such as America’s vast resources of oil shale. It is vital as a nation that we look to unconventional and nontraditional sources of energy to foster greater North American

energy independence.

I look forward to the testimony of our witnesses today. And when

our Ranking Member arrives, or a member of the other party arrives for this hearing, we will offer them an opportunity to make

an opening statement.

[The prepared statement of Mr. Gibbons follows:]

Statement of The Honorable Jim Gibbons, Chairman,

Subcommittee on Energy and Mineral Resources

The Subcommittee meets today to hold the second of a two-part hearing on ‘‘The

Vast North American Resource Potential of Oil Shale, Oil Sands, and Heavy Oils’’.

At Part 1 of this hearing we focused on dispelling the myth that the United States

has only 3 percent % of the world’s oil reserves.

A report by the Department of Energy that can be found on the Subcommittee

website estimates that the U.S. has 2 TRILLION barrels of oil shale out of the 2.6

trillion barrels found worldwide.

The domestic production possible from this resource would be sufficient to replace

all of the United States’ foreign oil imports except those from Canada and Mexico.

Also at the first part of this hearing, the Subcommittee heard from resource experts, resource producers, and State and local government representatives on a

range of topics, with a focus on the vast North American unconventional oil resource

potential.

Witnesses discussed the feasibility of developing unconventional oil resources.

Through the lessons learned from the oil sands production in Alberta, Canada, as

well as recommendations to facilitate commercial leasing and production of oil from

federally-owned oil shale, we learned that unconventional oil development is not

only feasible, but has the promise of delivering lower-cost oil to consumers.

83

I was very encouraged by the enthusiasm for oil shale production at the last hearing and look forward to hearing from officials from the Departments of Defense, Energy and Interior on their view of the federal government’s role in managing, utilizing, and facilitating production of the these unconventional sources of oil.

With approximately 70 percent of the land containing potential for oil shale development being owned by the federal government, the federal government will have

a vital role in the facilitation of production.

I believe the government has a responsibility to development of these valuable resources and this includes looking for ways to remove barriers to production.

As this Subcommittee has discussed in previous hearings, dependence on transoceanic energy imports is dangerous to our economic and national security.

Despite promises from OPEC to increase production from member countries, oil

prices have continued their movement higher.

Recent projections show that oil prices could reach more than $100 per barrel in

the not too distant future.

World oil supplies are growing tighter due to the inability of oil production to

grow as fast as increases in oil demand, primarily because of increased demand

from countries with rapidly growing economies such as China and India.

Global oil supplies are also strained because areas that would be highly prospective for energy production are either off-limits to leasing or the resources are not

otherwise being made available for leasing, such as America’s vast resources of oil

shale.

It is vital that as a nation we look to unconventional and non-traditional sources

of energy to foster greater North American energy independence.

I look forward to hearing the testimony of our witnesses.

Mr. GIBBONS. At this time, I would like to welcome our guests

and witnesses on our panel: Dr. Theodore K. Barna, Assistant Deputy Under Secretary of Defense, Advanced Systems and Concepts,

Office of the Secretary of Defense for the U.S. Department of Defense; Mr. Mark Maddox, Principal Deputy Assistant Secretary, Office of Fossil Energy, U.S. Department of Energy; and Mr. Chad

Calvert, Deputy Assistant Secretary, Land and Minerals Management, U.S. Department of the Interior.

Gentlemen, before I turn to your testimony, we have a procedure

to swear in our witnesses. So if each you would, rise and raise your

right hand.

[Witnesses sworn.]

Mr. GIBBONS. Let the record reflect that each of the witnesses

answered in the affirmative.

We will turn now to Dr. Barna, Assistant Deputy Under Secretary of Defense, for your remarks. Dr. Barna, the floor is yours.

We look forward to your testimony.

We do have a light system here. Each of your written remarks

will be entered into the record. You may feel free to summarize or

discuss your ideas within the five-minute time limit. But since I

am the only one here, you can take as much time as you want.

[Laughter.]

Mr. GIBBONS. Dr. Barna.

STATEMENT OF THEODORE K. BARNA, ASSISTANT DEPUTY

UNDER SECRETARY OF DEFENSE, ADVANCED SYSTEMS AND

CONCEPTS, OFFICE OF THE SECRETARY OF DEFENSE, U.S.

DEPARTMENT OF DEFENSE

Dr. BARNA. Thank you very much, Mr. Chairman. I am Ted

Barna, and I am very honored and delighted today to have the

chance to appear here and discuss the production of fuels for the

Department of Defense.

84

While I believe the Department of Defense, DOD, has legitimate

concerns about future access to energy—for example, increasing

amounts of imports and refined products, which you just mentioned—today I would like to concentrate on the work that we,

DOD, have performed to investigate and certify these fuels in military equipment. The end goal is to validate the use of these fuels,

and also reduce the number of fuels that we need to operate.

We started this, actually, back in 2003, before the current runup in prices, when I was asked to manage a program designed to

investigate alternative fuels. This is an ongoing study. It was initially sponsored by Senator Inhofe and Congressmen Sullivan and

Cole, all of Oklahoma. And we researched fuels produced via the

Fischer Tropsch process from natural gas.

Now, to accomplish this, I initiated a multi-service, multi-agency

program, led by the Army’s National Automobile Center—Automotive Center, I guess, the NAC—in Warren, Michigan. And the

NAC then formed a collaborative program with the Air Force, with

the Navy, with the Department of Energy, with the Department of

Energy National Labs in West Virginia and Pennsylvania, and

Southwest Research Institute in San Antonio.

We also were joined by several universities and industry; the industry partner being Syntroleum Corporation, who actually made

the fuel. We would use this to conduct a preliminary evaluation of

how these fuels could be, or would be, used in aircraft, tactical vehicles, and ships.

It is important to note that we did not address any of the economics of manufacturing these fuels. We were looking solely at

their potential use by the military.

As a result of this initial look, this initial look indicated that

these Fischer Tropsch fuels have a strong potential to produce

lower-pollutant emissions in diesel engines, reduce particulate

emissions in jet engines; they have superior high temperature and

low temperature characteristics; and they actually provide improved storage characteristics, especially on ships.

Based on these positive results, in 2004 I expanded this effort

then to include not just Fischer Tropsch fuel made from natural

gas, but looked at all the variety of resources we as a nation have

at our disposal; mainly, oil shale, sands, coal, biomass, and petroleum coke.

And although this, what we term as our OSD Clean Fuel Initiative, looks at the total energy picture, today I will just discuss two

of these: coal, very briefly; and shale, in more detail.

As you mentioned the U.S. has the necessary resources of coal

in Appalachia, the western United States, and Alaska—and this is

probably in excess of 800 billion barrels equivalent of oil—to

produce clean military fuels using Fischer Tropsch processes. And

as I stated previously, our work thus far has demonstrated these

fuels have excellent characteristics, and will be beneficial.

In addition, the gasification process used to produce these fuels

theoretically can be used to generate electricity, hydrogen, fertilizers, and chemicals. So it is a good opportunity for industry.

America’s shale, though, western shale, as you stated, deposits in

Colorado, Utah, and Wyoming, contain the equivalent of at least a

85

trillion barrels. And that would be well suited for producing a premium quality diesel and jet fuel for the military.

Eastern oil shale also represents about 400 billion barrels potentially of oil. And 90 percent of these near-surface mineable

resources are in Kentucky, Ohio, Indiana, and Tennessee. So we do

have shale in the east, actually; not in the strong concentrations

we have in the west.

DOD tests conducted in the early 1980s, back when we were interested in shale, demonstrated that shale oil derived from kerogen, when properly hydrogenated, has properties similar to crude

oil. For example, a U.S. Navy report of the period states that reasonable quality JP-5, which is the Navy jet fuel, and a marine diesel could be produced from shale oil, by virtue of their tests.

At the time, the Air Force also investigated JP-4, which we all

remember as our old jet fuel from the Air Force, and performance

was found satisfactory; although there were some lubricity issues,

that are easily solved.

A fresh look, though, at shale-derived fuels will be required, because now we use a different fuel. It’s called JP-8, which is a

version of the commercial Jet-A-1. This fresh test includes new

specifications designed to yield fuels that produce less tailpipe

emission SOXs and particulate matter, and have improved low

temperature characteristics; and then to certify use in all military

tactical vehicles, such as tanks, ships, and airplanes.

We know that this is just a burgeoning industry, but we have already made arrangements with Shell Oil to get some of their shalederived fuel and start this testing.

Looking in the future, shale-derived fuels could also be used in

fuel cells and advanced propulsion systems, such as hypersonics.

Therefore, based on our experience from the ’80s, plus new specifications and applications for extraction and refining, there is no

reason to expect that shale oil cannot be processed into high-quality, clean fuels which are suitable for tactical and non-tactical military equipment.

So in conclusion, if economic, utilizing all our energy sources—

the largest of which are shale and coal—while reducing the number

of fuels we employ, would have significant operational and logistics

consequences for the Department of Defense. Finally, cleaner fuels

would bring DOD more in line with current and evolving EPA regulations, and contribute to advanced technologies like hydrogen vehicles, fuel cells, and scram jets.

Mr. Chairman, I look forward to working with you and members

of the Committee as we pursue this mission of improving DOD’s

energy security. Thank you.

[The prepared statement of Dr. Barna follows:]

Statement of Dr. Theodore K. (Ted) Barna, Assistant Deputy Under

Secretary of Defense, (Advanced Systems and Concepts)

Introduction

Mr. Chairman and members of the Committee, I am Dr. Ted Barna, Assistant

Deputy Under Secretary of Defense, Advanced Systems and Concepts. I am honored

and delighted to have the chance to appear today to discuss opportunities to produce

superior fuels for the Department of Defense (DoD).

86

DoD’s Concerns

Supply vulnerabilities: As you are well aware, the U.S. currently imports over

56% percent of its oil and the Energy Information Agency estimates that it will increase to 68% by 2025.

Refining concerns: We are also increasingly dependent on foreign refined fuels, estimated to increase to four million barrels a day of finished product by 2025.

EPA Exemptions: The military currently has EPA national security exemptions to

use jet fuels in our tactical equipment that in some cases exceed local EPA requirements. As President Bush stated ‘‘America must have an energy policy that plans

for the future, but meets the needs of today. I believe we can develop our natural

resources and protect the environment.’’

Reduce the number of fuels: If economic alternatives can be founds, a reduction

in the number of fuels DoD currently uses would generate a tremendous operational

and logistic benefit. Therefore, a significant goal of our ongoing program is geared

to eventually having one battlefield fuel which can be used in the air, on ground,

or at sea. Since this fuel would be suitable for the intended function (fit for use)

the source of the fuel (synthetic, shale, biomass, petroleum) would be immaterial to

the ultimate consumer.

Sources of energy: A quick estimate of total energy resources (shale, coal, oil, and

other resources such as biomass and petcoke) comes to approximately 2.3 trillion

barrels (bbl) potentially available in the US. (This total estimate includes: 1.4 trillion bbl of shale; 800 billion bbl coal; 60 billion bbl of petroleum, including enhanced

oil recovery using CO2; plus renewables, which are not yet quantified). This compares with an estimated 700+ billion barrels total proved reserves (producible at today’s prices) in the entire Middle East.) Please note, (‘‘resource’’ is a technical term

that indicates supplies of energy that may be in the ground, but are not economically producible at today’s prices).

Note: EIA estimates U.S. proved oil reserves at 24.0 billion barrels as of the beginning of 2003. For technically recoverable oil resources, EIA uses estimates from

the U.S. Geological Survey and Mineral Management Services, to arrive at an estimate of 142.8 billion barrels as of the beginning of 2003. The 800 billion bbl estimate for coal represents recoverable reserves only, not total resources. DOE estimates oil shale resources at more than 2 trillion barrels, although the economics of

the recoverability of this resource is not considered.

In sum, if economic, the development of the vast national energy resources we

have in this country could provide a dispersed, diverse, less vulnerable supply of

fuels for the military such that it can meet its national security objectives in the

near and far term.

DoD Involvement

Starting in 2003, before the current run up in prices, I was asked to manage a

program designed to investigate alternative fuels. This ongoing study, sponsored by

Senator Inhofe and Congressmen Sullivan and Cole, all of Oklahoma, researched

fuels produced via the Fischer Tropsch (FT) process from natural gas. To accomplish

this task I initiated a joint program, led by the Army National Automotive Research

Center (NAC) in Warren, Michigan, to investigate the military utility of these fuels

and to evaluate the potential of producing and using a new generation of clean fuels

for the military. The NAC in turn formed a joint collaborative program with the Air

Force Research Laboratory at Wright-Patterson AFB, Ohio, the Naval Air Systems

Command located at Patuxent River, Maryland, the Department of Energy National

Technology Laboratory in Pittsburgh, Pennsylvania, and the Southwest Research

Institute, San Antonio, Texas. They were joined by the University of Dayton Research Institute in Dayton, Ohio, and Syntroleum Corporation, Tulsa, Oklahoma

(which supplied the fuel) to conduct a preliminary evaluation of the technological

potential of these fuels for use in aircraft, tactical vehicles and ships.

The team has concluded a preliminary assessment of the chemical properties,

storage stability, thermal stability, low temperature characteristics and emissions in

diesel and jet engines. It found that neat (100%) FT fuel will require modification

for use in legacy (older) military equipment, but these modifications can be made

with existing technologies. For example, since the fuel is highly processed, it has

a lower lubricity than normal petroleum derived fuels and could lead to premature

pump failures. The research team has determined that conventional lubricity additives or blends with petroleum derived fuels could easily remedy this problem. Also,

since these fuels are very good solvents, they can cause the elastomers (seals and

o’rings) found in legacy systems to shrink and potentially cause leaks. Continuing

research to solve this problem includes novel additives, aromatic blends, and blends

with conventional petroleum derived fuels.

87

Bottom line is these are fuels that meet or exceed military and EPA standards.

Use of pure synthetic fuels pose some difficulties in the areas of lubricity and seal

swell, especially in legacy (older) equipment, but the problems can be solved at some

cost, initially by using blends and ultimately by the addition of additives. They also

bring us more in line with EPA and EU regulations. Testing and characterization

now pro-actively identifies and could significantly ease future difficulties.

It is important to note this effort did not address the economics of using clean

fuels for the military, nor whether or not it is ever likely that commercial scale production by the private sector will occur.

The results of this initial look indicated FT fuels, using updated processes and

procedures, have the strong potential to produce lower pollutant emissions in diesel

engines, reduce particulate emissions in jet engines, have superior high temperature

and low temperature characteristics, and provide improved storage characteristics.

Even the use of clean fuel blends, designed to counter problems of lubricity and sealswell, provide significant (50%) reductions in tailpipe emissions.

Based on these finding, in 2004 I expanded this initial effort to include a wider

variety of resources for the production of clean fuels, notably: oil shale, oil sands,

coal, biomass and petroleum coke. Although this OSD Clean Fuel Initiative looks

at the total energy picture, today I’ll concentrate on only two of these resources: coal

(briefly) and shale (in more detail).

Coal

The U.S. has the necessary recoverable reserves of coal in Appalachia, the western United States, and Alaska (approximately equivalent to 800 billion barrels) to

produce clean military fuels via the above mentioned Fischer-Tropsch process or

through direct liquefaction. In either case, since the coal is gasified to carbon monoxide and hydrogen, then recombined over a catalyst, these processes remove most

if not all pollutants, including sulfur and mercury. When coupled with carbon strategies, such as CO2-sequestration, while more costly than alternatives, the entire

process is certainly more environmentally friendly. In addition to producing military

fuels, this coal gasification process can be used technically to generate electricity,

hydrogen, fertilizers, and chemicals.

Oil Shale

America’s Western Oil Shale is the largest unexploited hydrocarbon resource on

earth. It’s estimated that deposits in Colorado, Utah and Wyoming contain approximately 1 trillion barrels of recoverable oil (equivalent) that are well suited for producing premium quality diesel and jet fuels for the military. For example, Shell Oil

is currently conducting a shale oil conversion pilot project which will convert kerogen to oil and gas via thermal cracking and in situ hydrogenation. Eastern Oil

Shale could provide 400 billion of barrels of oil based on estimates in the 1990’s,

(Dr. Ari Geertsema, Center for Energy Institute, University of Kentucky). These

eastern oil shale deposits are not as concentrated as western shale It is of interest

that, while not as concentrated a Western Shale, Eastern Shales are low in carbonate content and retorting will not cause decomposition and the production of

large amounts of CO2. Greater than 90% of the near-surface mineable resources are

in Kentucky, Ohio, Indiana and Tennessee.

DoD demonstrated in the early 1980’s that shale oil derived from kerogen, when

properly hydrogenated, has properties similar to crude oil. Since no shale fuels have

been produced lately because of the cost of production, our evaluation relies on interpreting archival data. The technical literature reports early laboratory work on

producing quality jet fuels from shale oil as early as 1951. Understandably, DoD interest increased dramatically in 1973 following the Arab Oil Embargo.

The initial large scale evaluations of petroleum refined from shale oil were sponsored by the Navy and the Naval Petroleum and Oil Shale Reserves Office. These

investigations looked at gasoline, JP-4 (Air Force standard jet fuel during this period), JP-5 (Navy aircraft fuel), diesel fuel marine (DFM) and a heavy fuel oil. Eventually, quality fuels were produced under these contracts and the Navy and DOE

conducted extensive tests in military and commercial equipment. The initial focus

of the testing was on the DFM product for naval shipboard use and included evaluating the fuel in fuel pumps and fuel distribution equipment to assure compatibility

with Navy fuel system materials. After a complete evaluation, the Navy conducted

hardware tests in diesel engines, Navy boilers, marine gas turbine engines, and conducted a shipboard test on the USS Scott. The Navy reports showed that DFM produced from shale oil was suitable for shipboard use.

The Navy also conducted tests of a shale derived JP-5 fuel in aircraft engines. The

Navy report of the period states that a reasonable quality JP-5 could be produced

(although the fuel was somewhat more corrosive than some petroleum derived fuels)

88

and required the addition of lubricity additives for fuel pump durability. Engine

tests were conducted by Allison on the T63-A-51 and T56-A-14 engines; General

Electric on the TF34-GE-400 engine; and Pratt and Whitney TF30-P-414 engine.

The shale derived JP-5 fuel performed satisfactory in all tests.

At the same time, the Air Force investigated shale derived JP-4 fuels. The fuel

was tested in combustion rig tests conducted by Pratt and Whitney and General

Electric and the fuel found to be suitable for testing in full scale engines and aircraft. Accelerated durability testing was also conducted by United Technologies on

shale derived JP-4 in the TF30 and F100 fighter engines. Performance was found

to be satisfactory in these engines tests, although the reports recommended additional research on fuel lubricity additives. Based on these positive results from the

engine tests, a plan was developed to use the fuel at Air Force Bases in Utah (Hill

AFB) and Idaho (Mountain Home AFB). The program was abruptly brought to an

end by the announcement by Exxon of the closure of the Colony Project signaling

the end of this phase of oil shale development.

Therefore, our conclusion is that shale oil can technically be processed using conventional refining techniques into high quality clean fuels, which are suitable for

general use, to include use in tactical military equipment.

Notwithstanding these favorable results, a fresh look at shale derived fuels will

be required by the military since the main jet turbine fuel is now JP-8, a version

of commercial jet fuel Jet-A1, which replaces the JP-4 (gasoline/kerosene fuel blend)

used by the Air Force and diesel fuel used by the Army. This fresh look includes

developing new specifications designed to yield fuels that produce less tailpipe emissions (SOx and particulates), have improved low temperature characteristics, and

allow use in all military tactical vehicles such as Army tanks, Navy ships, and Air

Force and Navy aircraft.

Looking to the future, economic shale derived fuels produced to clean fuels specifications could also be used in fuel cells and advanced propulsions systems required

for hypersonics.

Therefore, based on our experience from the 1980’s, plus new specifications and

application of modern extraction and refining techniques, there is no reason to expect that shale oil cannot technically be processed into high quality clean fuels,

which are suitable for use in tactical and non-tactical military equipment.

Conclusion

If economic, a reduced number of fuels would have significant operational and logistics consequences, and supply chain vulnerability would be reduced by having

more, dispersed refineries. Cleaner fuels would bring DoD more in line with current,

and evolving EPA regulations, reduce the possibility of limits on potential deployment (i.e. EU) locations, and contribute to technology advancements, (for example

hydrogen vehicles, fuel cells, and scram jets).

Mr. Chairman, I look forward to working with you and the members of the Committee as we pursue our mission of providing DoD energy security.

I would be pleased to answer any questions.

Response to questions submitted for the record by Dr. Theodore K. (Ted)

Barna, Assistant Deputy Under Secretary of Defense, (Advanced Systems

and Concepts)

1. What are the three most important things that the Federal Government can do

to ensure timely production of large volumes of oil from oil shale?

First, the Department of Defense (DoD) can act as a preferred customer of the

jet fuel produced from the shale. Historically, DoD was slated to be the first user

of fuels produced from oil shale in the late 1970’s and early 1980’s. Plans were in

place to use the fuel at key Hill and Mountain Home USAF bases prior to the program being cancelled. A similar approach to be a dedicated customer would be a

good first step to a broader usage by the DoD.

Second, another key role the DoD can play is to evaluate, certify, and demonstrate

that fuels produced from the shale oil are fit-for-purpose for use in trucks, aircraft

and ships. DoD working closely with the original equipment manufactures (OEM’s)

to assure compatibility, performance and durability, paves the way for the military

to use fuels produced from this resource.

Third, DoD can serve as the focal point for developing new fuel specifications, in

concert with manufacturers, that meet the needs of the military and civilian clients.

These revisions are long overdue and can serve as the basis for improved efficiencies

and lessened logistics tails.

89

2. Specifically, what does the Department of Defense plan to do, if anything, to en- sure production of oil from oil shale? Would it be possible for DOD to enter into

long-term contracts for the purchase of oil produced from oil shale, with provisions allowing for protection of the producer from downside price risks, while allowing DOD to be protected against large price increases?

The Department of Defense is following the programmatic efforts of the Depart- ment of Energy and industry to develop the resources. The DoD is developing plans

to evaluate, certify, demonstrate and implement use of fuels produced from oil shale

that would mesh with the development of the resource.

Currently the DoD by statute can enter in to multiyear contracts for fuel produced from shale oil at market price. That is, while the contract is for a longer term, the

price is renegotiated yearly. The DoD could offer a preference for fuel produced from

oil shale in its open solicitations for jet fuel. Currently DoD is prohibited from entering into contracts that would allow protection of the producer for downside price

risk, or the DoD to be protected against large price increases (floors and collars).

3. What quantity of oil and products derived from oil does DOD consume annually? Of this amount, how much do you foresee could be provided by oil and products

produced from oil shale?

The Defense Energy Support Center (DESC) issued contracts in FY04 to purchase 127.4 million barrels (5.35 billion gallons) of fuel. 75.6 million barrels (3.18 billion

gallons) was purchased domestically. (Reference DESC Fact Book 2004) When the

oil shale resource is developed, shale derived fuels could provide a significant share

of the fuel we use domestically and supply key military bases in the western United

States.

4. Does DOD consider that relying on vast quantities of transoceanic oil imports is a threat to the national security of the United States?

For the foreseeable future, the U.S. will continue to rely on imports for a majority of its fuel needs. However, fuel is a fungible commodity traded in an efficient global

market. Reselling quickly and substantially mitigates the effects of supply interruptions at any one source as well as to any particular market. While the U.S. economy will be affected by long-term increases in global fuel prices stemming from, e.g., increased global demand and political instability among

energy suppliers, several factors attenuate the danger to national security: • The U.S. economy is less ‘‘energy intensive’’ (defined as the fraction of every dollar of GDP spent on energy) than any other major mature market economy, and

therefore can absorb price increases more easily. • Because of technological innovation in energy use and advances in exploration,

the historical trend in global energy prices has been downward, consistently

defying forecasts. • Even assuming upward price trends in the future, as energy prices increase, alternative sources of energy (such as shale oil) will become cost-effective at different points, thereby dampening further price increases for traditional sources.

5. What are your recommendations for coordinating the Defense mission with Energy and Interior missions? If Congress were to establish a tri-agency Task Force to

complete the program planning, would that fit with your vision?

The Department of Defense would support a tri-agency Task Force and support the development of multi-agency plans. The task force could develop plans and roadmaps to assure rapid development of the resource and reduce the impediments and

hurdles industry currently faces to develop the resources. The task force could

streamline the federal processes related to environmental assessments, federal land

usage, surface and underground shale retorting, shale oil upgrading and distribution.

6. You testified that it is your mission to design new fuel specifications, perhaps for a dual-purpose fuel, and to qualify fuels conforming to these specifications. As we

build an oil shale industry, do you see your qualifying program as having implications to the civilian sector? Would you outline the prospective steps to accomplish your mission?

Original equipment manufacturers (OEM’s) will have reluctance to certify the use of fuels from any non-petroleum resources until they are satisfied that the fuel is

fit-for-purpose, does not cause any adverse performance or durability issues, and

offer similar or better operational performance compared to conventional petroleum

derived fuels. As the military uses equipment that is similar to some of the equipment the civil sector uses, the qualification and demonstration of the fuel in military

hardware would allay concerns the OEM’s would have. The military would work

closely with OEM’s during the evaluation, certification and demonstration phases

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and the results should be available for them to help certify the use of the fuel in

civilian equipment.

The fuel would be evaluated using standard laboratory tests to determine the

physical and chemical characteristics and determine the differences compared to petroleum derived fuels. Fuels will be tested in reduced scale weapon system simulators and in subscale components. The fuels would be tested to assure compatibility

with the materials of construction of vehicle fuel systems, and tested at the component level to assure performance, suitability and durability for testing in full-scale

equipment. The fuel would be tested in army ground tactical vehicles, aircraft and

ships to assure long term durability and performance and to achieve certification

for continuous use by the OEM’s. Weapon system documentation will be updated

and as production increases the fuel use would be implemented at test bases. The

initial bases will be monitored to collect long term use information and full implementation would progress as fuel supplies become available.

Mr. GIBBONS. Dr. Barna, thank you very much for your testimony. It is certainly a pleasure to have you with us today, and you

have been very helpful.

We will turn now to Mr. Mark Maddox, the Principal Deputy

Assistant Secretary, Office of Fossil Energy for the United States

Department of Energy. Mr. Maddox, welcome. The floor is yours.

STATEMENT OF MARK MADDOX, PRINCIPAL DEPUTY

ASSISTANT SECRETARY, OFFICE OF FOSSIL ENERGY, U.S.

DEPARTMENT OF ENERGY

Mr. MADDOX. Thank you, Mr. Chairman, for this opportunity to

testify on oil shale and its potential for increasing our Nation’s

energy security by mitigating our dependence on imported oil.

Our domestic shale oil resource of more than 300 billion barrels

of recoverable oil could play a significant role in meeting the Nation’s future demand for liquid fuels. With high oil and gas prices,

industry has strong incentives to develop technologies that can

bring shale oil and other non-conventional fuels into production on

an economically and environmentally sound basis.

This Administration strongly supports efforts by the private sector that could result in adding shale oil to the Nation’s energy portfolio, therefore strengthening energy security. The Nation’s oil

shale resource is concentrated in pockets in Utah, Colorado, and

Wyoming, and 80 percent of the resource is owned by the Federal

Government. The resource is so large, even if only partially developed, it could deliver 2 to 3 million barrels per day for decades.

But in order to tap this enormous energy resource, industry must

develop economically and environmentally sound technologies, as

we attempted to do after the oil interruptions and price shocks of

the 1970s, when the Federal Government encouraged the development of oil shale and other unconventional domestic resources.

Those efforts were abandoned when both government and industry concluded that the world oil market could provide adequate

supplies, reasonable prices, and sufficient excess capacity. Many

current observers of the market, however, question whether that

conclusion still holds today, or will hold again.

From the beginning in 2001, President Bush has emphasized the

desirability of reducing our reliance on imported oil. The benefit of

2 to 3 million additional barrels per day of secure domestic oil from

shale is obvious. If that oil were available today, it would reduce

our dependence on imported oil by as much as 25 percent. ComVerDate 11-MAY-2000 13:51 Nov 22, 2005 Jkt 000000 PO 00000 Frm 00096 Fmt 6601 Sfmt 6602 J:\DOCS\22327.TXT HRESOUR1 PsN: HRESOUR1
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bined with the Administration’s other long-term programs to reduce oil demand growth, shale oil could have a powerful and beneficial effect on future oil import levels.

But there are numerous challenges to development, including the

attitude of the public, business and investment considerations, and

land access and usage, and environmental concerns. These challenges are surmountable, given a real commitment and close coordination among all the players, public and private, in the energy

sector.

Unfortunately, the shale oil development work of 30 years ago

left a legacy of uncertainty for industry and the public, particularly

for people living in the centers of development. The affected areas

enjoyed a boom period during development, followed by a devastating bust that has left them understandably wary.

Fortunately, it appears the citizens of these areas are ready to

give oil shale another chance and support a new development effort, but only with more planning and support for infrastructure

and development.

The oil industry today is finding most of its attractive investment

opportunities overseas. But as conventional oil plays become more

difficult and conventional oil production peaks, industry will again

look to the development of higher-cost resources such as shale oil.

How long this process will take is an open question. The answer

will depend on economics, and the economics will be determined by

projected oil price trends, tax rates, resource access, royalty regulations, permitting requirements, and the receptivity of state and

local populations to development.

Looking down the list, it is clear the Federal Government and

state governments will have a large role to play in removing road

blocks and encouraging private sector interest in shale oil development.

A key development concern will be the environmental impact of

extracting oil from shale by using technologies to heat the rock, either above or below ground. Despite the significant research and

development work conducted 20 to 30 years ago, the industry has

not yet reached a consensus on the best technology to use.

Regardless of the process, shale oil operations will have some environmental impact, as does any industrial operation. As always,

the job of everyone involved in development will be to ensure that

the impact is minimal and acceptable.

Fortunately, we have a very successful model for the development of oil shale, through the production of over 1 million barrels

per day of oil from Canada’s Alberta oil sands, where production

is expected to exceed 2 million barrels per day in eight years.

Many parallels exist between shale oil and oil sands technologies,

markets, and economics. We cannot be certain that oil shale economics will parallel those of the Alberta tar sands. There are important physical differences between oil sands and oil shale, and

the extraction technology for one cannot directly be transferred to

the other.

But comparisons suggest that the domestic oil shale industry is

in some ways similar to the Canadian oil sands industry of 30

years ago. As part of its energy security goal, the Department is

committed to improve energy security by developing technologies

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that foster a diverse supply of reliable, affordable, and environmentally sound energy, and improve our mix of energy options. This prospect of adding 2 to 3 million barrels a day of secure do- mestic oil to our Nation’s energy supply for decades to come demands our attention and our support. The Department will work

to achieve this goal in support of the economic security of the

United States, in line with our commitment to deliver results for

the American taxpayer. Mr. Chairman, this concludes my prepared statement. I will be happy to answer any questions from you and the Committee. [The prepared statement of Mr. Maddox follows:]

Statement of Mark Maddox, Principal Deputy Assistant Secretary for Fossil Energy, U.S. Department of Energy

Mr. Chairman, Members of the Subcommittee, thank you for this opportunity to testify on oil shale and other non-conventional oils, and their potential role in elevating our Nation’s energy security by mitigating our dependence on imported oil.

U.S. energy security is important by virtue of the crucial role it plays in achieving

economic security. I would like to share with you today our thoughts on the oil shale resource in these areas—first, oil shale’s magnitude and potential; then, the history of past unsuccessful attempts to develop it; and, finally, barriers to development as they exist

today. In addition, I will compare the prospects for oil shale with the commercial

development experience of another non-conventional resource, Alberta’s vast oil

sand resources.

Ensuring the present and future energy security of the United States is a primary goal of the Office of Fossil Energy, and we are committed to the President’s goal

of elevating our energy security through increased production of economic domestic

resources. Domestic oil shale represents a resource of more than 300 billion recoverable barrels of oil and is a resource which, if economical, could play a significant

role in meeting the Nation’s needs for more liquid fuels over the next several decades.

We also have potential domestic sources of non-conventional liquid fuels such as

the technologically mature but uneconomic Fischer-Tropsch coal liquefaction, recovery of stranded oil, undiscovered oil and other currently uneconomic resources. With

high oil and gas prices, industry has strong incentives to develop technologies that

will facilitate exploration of non-conventional domestic resources, and in fact there

is evidence that they are doing so.

The Resource

The total U.S. oil shale resource is estimated to be 1.8 trillion barrels and is primarily concentrated in the Green River formation in northeastern Utah, northwestern Colorado, and southwestern Wyoming. Over 50% of the world’s oil shale

resources are in this area, 80% of which are owned by the Federal Government. It

is estimated that over 400 billion barrels of oil equivalent exist in oil shale at concentrations greater than 30 gallons/ton. In 1980, the Office of Technology Assessment published An Assessment of Oil Shale Technologies, which estimated that between 189 and 315 billion barrels of oil would be recoverable from this high quality

shale. Oil and Gas Journal, in its August 9th 2004 issue, suggested that 100 billion

barrels of oil from domestic oil shale could be reclassified as proven reserves if the

technology became commercially viable. Suffice it to say, if it were financially feasible to even partially develop, the resource could sustain an industry of 2-3 million

barrels per day for decades.

The factors that limit the development of oil shale have nothing to do with the

potential quantity of the resource. Historically, oil shale production hasn’t been economical. The cost of production has been too high compared to the cost of producing

from conventional resources. This problem has been compounded by the need to

build an infrastructure to support oil shale and the cost of disposal of byproducts.

Although the Federal Government attempted to make oil shale economical in the

late 1970’s and early 1980’s, this effort was abandoned because shale oil production

could not be sustained in the face of abundant and cheap conventional crude oil.

This was true even though the Government embarked on this effort at a time when

oil prices were higher in real terms than they are today. The failure of the

Government’s efforts in the 1980’s was not due to the failure of the resource, the

technology, or environmental problems; economically it was simply too expensive.

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Recently, however, industry has shown renewed interest and has begun committing

resources.

What is the Commercial History of Oil Shale in the United States?

After the oil interruptions and price shocks of 1973-74, the Federal Government

encouraged the development of unconventional domestic resources including oil

shale. The Department of the Interior offered commercial leases for development in

1973. Bonus bids totaled $450 million for four oil shale leases and industry began

development. Economic incentives were later offered for oil shale development including a guaranteed price floor ($42.50 indexed to the CPI), and a production tax

credit of $3 per barrel. In total we estimate $5 billion was invested in oil shale facilities beginning roughly in 1975. Major players at that time included Exxon, Shell,

Mobil, Occidental, Atlantic Richfield, Chevron, and Unocal. In the early 1980’s these

projects began to close and the last closed in 1992. The consensus of the industry was that oil prices simply did not stay on a price path over the long term that would assure a reasonable return on investment for

an unconventional crude oil. In addition, policy changes accompanying new administrations removed the subsidies for synthetic fuels. Witness the demise of the Synthetic Fuels Corporation, which was chartered during the Carter Administration but

allowed to expire during the Reagan Administration. The oil price collapse of 1986

assured the end of the U.S. synthetic fuels industry. The general impression left following the demise of the U.S. oil shale industry was very negative. During the boom period, the influx of workers into Western Colorado

strained and ultimately overwhelmed the local infrastructure and housing, producing lasting socioeconomic effects. When the industry collapsed, the local towns

were left with infrastructure in excess to their needs, shrunken property values and

a tax base incapable of supporting the infrastructure.

How is Oil Produced from Oil Shale?

Kerogen, a low grade form of immature oil, is extracted from oil shale in a process called ‘‘retorting’’, which requires heating of the rock to about 900 degrees Fahrenheit. Two generic methods of retorting have been developed: • In situ: This method leaves the rock in place and injects a heat source that releases the oil from the kerogen. The shale oil then flows to a well and is

pumped to the surface. The source of the heat is a technical issue still open to

research and testing. The only active pilot project in the U.S., owned by Shell

Oil, is using down hole electric resistance heaters, but optional technologies involve steam, microwaves, and fire. • Surface retorting: This technology depends upon mined ore for a feedstock. The

ore can be either surface mined or mined underground. The ore is brought to

the surface, crushed and placed into a retort. The shale oil is removed and the

spent shale sent for disposal. The shale oil is upgraded by the addition of hydrogen and then is conventionally refined to produce finished products. Several different retort designs have been constructed and tested in the United States as

a part of earlier development efforts. However, there are currently no commercial surface retorts in the U.S. processing oil shale.

Challenges to Commercialization

Perceived Risk: Shale oil activities in the late 1970s and early 1980s have left a legacy of uncertainty. Members of industry and the citizenry alike are uncertain

about the risks associated with commercial development.

Current Oil Industry Economics: U.S. domestic oil production is high cost com- pared to many parts of the world because our fields are mature and declining. Private investment dollars are directed to the most economic areas where costs of production are low, like West Africa, Brazil, the Middle East, Russia and Central Asia.

As long as current geopolitical and market conditions persist, we expect more money

to flow to energy extraction on a world wide basis; however, not a large share of

it is expected to be invested in the United States in the immediate future. As conventional oil plays become more difficult to find, and as conventional domestic oil

production peaks, industry will again begin to focus on the development of the

resources that can be extracted profitably at higher prices, including oil shale. Prospects for commercial oil shale production will depend on the private sector’s

perception of the relative profitability of oil shale versus competing resources. Factors that will determine economics are projected oil price trends, tax rates, cost of

production, resource access, royalty payments, permitting requirements, cost of byproduct disposal, and the willingness of the State and local populations to host a

new industry.

The size of the industry will be limited by existing distribution, pipeline capacity,

water availability, power distribution, and refining capacity in this region of the

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Rocky Mountains. If the oil shale industry develops to any appreciable size, investments will be required to expand the limited infrastructure.

Land Access and Usage: A major driver of shale oil extraction economics is the

concentration of the resource. Movement of ore to the retort can be very expensive,

because the ore is mostly rock with only a little oil (more than one ton of ore per

barrel of oil). Therefore, the ore must be processed at or near the geologic formation

where it is found. While the natural resource is very concentrated in Colorado, Utah

and Wyoming, the ownership is not. The Federal Government owns 80 percent of

the resource base, and the remaining tracts are broken up. At this time the Department of the Interior does not have a commercial leasing program, although it recently established a leasing process for small tracts to conduct research, development, and demonstration projects and is accepting nominations from industry for

parcels to be leased.

Environmental Impact: The environmental impacts of shale oil development are

significant. Like the resource, they will primarily be concentrated in small geographic locations. Because oil shale is mined, there are surface impacts. Oil shale

production is water intensive, which is an important limited resource in the regions

with oil shale deposits. Because the retorting processes are energy intensive, there

are combustion emissions in areas where the air is currently very clean. The mining

or in situ technologies may also disturb the local water tables. In the case of the

in situ technology, the spent shale in place may contain toxins that need to be kept

away from ground water. In the case of surface retorting, the spent shale,

processing water, and other byproducts must be disposed of in a safe manner. How

to do that on a massive scale has not been defined. To produce a million barrels

of oil would require disposal of more than a million tons of byproducts.

The positive aspect of the resource is that its density is so great that most of the

environmental impacts can be restricted to a relatively small area within two or

three States. However, because shale oil production is energy intensive, the industry

could add significantly to green house gas emissions during production. Similarly,

greenhouse gas emissions will be released when the fuel is consumed.

Extraction Technology: Despite the significant research and development conducted 20-30 years ago, there is no accepted benchmark for the best technology to

use. Furthermore, because of modern developments in environmental protection and

resource conservation, it will be important for the existing technologies to improve

from an efficiency, and environmental impacts perspective. Companies will have to

advance extraction technologies through research, development, and demonstration.

Comparison with Alberta Oil Sand Commercialization

Commercial production from formerly uneconomical resources occurs as markets

change and drive technology development. Oil from Alberta oil sand, once considered

to be an unconventional resource, is being commercially produced today. Oil was

first produced at a commercial scale from Alberta oil sand more than 35 years ago.

Today, oil sand production is over one million barrels per day and is expected to

exceed 2 million barrels per day within the next eight years. A strong partnership

between government and industry stimulated more than $65 billion in private investment to accelerate development and achieve industry scale operations during

this decade.

Like oil sands, U.S. oil shale is rich, accessible, geographically concentrated, and

well defined. However, the technologies required for exploitation of oil shale are very

different from those required for oil sands. The richness of the respective resources

are similar, with oil sands yielding approximately 25 gallons per ton of bitumen

while some oil shale deposits yield an average of about 30 gallons per ton. A comparison of the qualities of the two oils shows them to produce a similar product after

processing. The Athabasca sand produces 34 degree API oil and the oil shale produces 38 degree API oil. However, there are important physical differences between

oil sands and oil shale and the extraction technology for one cannot directly be

transferred to the other.

Summary

In summary, we need to examine all of our resource bases if we are to do a credible job in protecting the United States’ energy security interests. As part of its

energy security goal, the Department is committed to improving energy security by

developing technologies that foster a diverse supply of reliable, affordable, and environmentally sound energy and improve our mix of energy options. The Department

will work to achieve this goal in support of the economic security of the United

States, in line with our commitment to deliver results for the American taxpayer.

Mr. Chairman, and members of the Subcommittee, this concludes my prepared

statement. I will be happy to answer any questions you may have at this time.

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Response to questions submitted for the record by Mark Maddox, Principal

Deputy Assistant Secretary for Fossil Energy, U.S. Department of Energy

Ensuring Oil Shale Production

Question 1. What are the three most important things that the Federal Government

can do to ensure timely production of large volumes of oil from oil shale?

Answer 1. It is most important to make land available for oil shale research and,

eventually, the production of oil shale. The first step in this area is progressing as

the Bureau of Land Management is currently accepting nominations of parcels for

a potential research and development scale leasing program.

Economical Analysis

Question 2. Your written testimony stated that U.S. oil shale resources contain at

least 300 billion barrels of recoverable oil IF ECONOMICAL. Has the Department

of Energy performed an analysis of whether production of oil shale is ECONOMICAL at this time? If you have not performed such an analysis, when do you plan

to do so?

Answer 2. We have performed an analysis of the economics of oil shale. As part

of our analysis of the industry we have developed a model to evaluate project economics for the application of oil shale technologies to selected resource tracts, and

the relative impact of various incentives on project economics.

As there are no commercial oil shale facilities operating in the United States, our

analysis cannot be based on realized costs from any such current operations. Several

oil shale projects were undertaken domestically in the 1970s and 1980s, most notably Unocal’s operations in Parachute Creek, Colorado. However, we have no direct

information on the costs these operations experienced. Some indirect evidence comes

from the fact that Unocal ultimately determined its operations to be uneconomical,

despite receiving a guaranteed price of $41.50 per barrel under a long-term supply

contract reached in 1981 with the Department of Defense. Converting from 1981

dollars, this guaranteed price would correspond to more than $80 per barrel in 2005.

In the absence of data on realized costs, our analysis is based primarily on engineering models developed in the 1970s in conjunction with the 1974 Prototype Oil

Shale Leasing Program (POSLP). These models provide capital cost and production

cost estimates for various technologies, which we have escalated to 2004 dollars

using Bureau of Labor Statistics data and have further validated with current vendor quotes. The analysis also applies resource characterization data from surveys

conducted by the U.S. Geological Survey (USGS) in preparation for the POSLP. The

economic analysis examined the USGS defined resource tracts to determine the

most efficient technology for resource extraction at each location. The production

cost estimates and resource characterization data were then used to calculate minimum economic prices.

We define the minimum economic price as the break even price for a mature industry, one that has already recovered substantial initial costs (associated with research and development, permitting and land access) and has achieved substantial

cost reductions through learning-by-doing. If we were to include estimates of these

initial costs and the likely inefficiency of early plants into our calculation of minimum economic prices, the figures listed in the table below could more than double.

Our model estimates cash flow for the various projects by evaluating plant capacity, development schedule, market prices for oil and natural gas, leasing royalty

structure, operating costs, capital costs, and tax structure. The table below summarizes the model results for the four known extraction technologies. The average minimum economic cost shown in the table below represents the average of the breakeven prices for a given technology across the resource tracts where it is being applied. Capital costs are the sum of investments needed per barrel of installed capacity. These costs include investments in mining, retorting, solid waste disposal, refining and upgrading, plant utilities, and other facilities. Operating costs include fuel,

operating and maintenance personnel, consumable equipment and other non-capital

costs for mining, retorting, refining and upgrading. The components of both capital

and operating costs are different for various technologies used for mining, retorting,

and upgrading.

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Reclassification of Proven Reserves

Question 3. Am I correct that when that analysis has been completed, and assuming

that the analysis shows that production of oil from oil shale is economical, large

quantities of domestic oil shale resources could be reclassified as proven reserves?

Wasn’t this confirmed by the Oil and Gas Journal in its August 9, 2004 issue?

Answer 3. No. The classification of proved oil and gas reserves is regulated by

the Securities and Exchange Commission. Proved reserves are defined in Rule 4-

10(a) of Regulation S-X of the Securities Exchange Act of 1934.

‘‘Proved oil and gas reserves are the estimated quantities of crude oil,

natural gas, and natural gas liquids which geological and engineering data

demonstrate with reasonable certainty to be recoverable in future years

from known reservoirs under existing economic and operating conditions,

i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided by contractual arrangements, but not on escalations based upon future conditions.

‘‘Existing economic and operating conditions are the product prices, operating costs, production methods, recovery techniques, transportation and

marketing arrangements, ownership and/or entitlement terms and regulatory requirements that are extant on the date of the estimate.’’

As the rule indicates, the resource needs to be under development with commercially proven technologies to be classified as a proved reserve. In addition, Rule 4-

10(d) of the same law explicitly prohibits oil from oil shale (along with coal and gilsonite) as being classified as a proved oil and gas reserve. This prohibition is based

largely on economic uncertainties, including the lack of existing markets. The rule

leaves open the possibility of classifying these types of resources as proved reserves

if markets develop and companies demonstrate commitment to develop the necessary production. However, the SEC currently treats oil shale development as a

mining activity. The classification of proved reserves of ore for mining activities is

regulated by SEC Industry Guide 7 and it appears that the geologic analyses conducted by the USGS would be sufficient to recharacterize the oil shale resources as

proved reserves, if they were developed.

As a comparison, the Alberta oil sands resource is estimated to total well over 1

trillion barrels. It was only in 2004, however, that 174 billion barrels were finally

reclassified as proved reserves, this coming after over 40 years of work developing

the resource. Again, this is because, as with U.S. law, Canadian law requires that

the resources be developed, that commercially viable production be demonstrated,

and that economic conditions support the long-term exploitation of the resource.

EIA Reserves Estimate

Question 4. On April 12, you testified before the Senate Committee on Energy and

Natural Resources that ‘‘our domestic total oil shale resource is more than 1.8 trillion barrels, with perhaps 100 billion to 200 billion barrels commercially viable.’’

Based on this position, when will the Energy Information Agency take action to

recharacterize that amount of resource as reserves?

Answer 4. The Energy Information Administration (EIA) currently recognizes a

very small part of the nation’s oil shale resource as proved reserves as does the Securities and Exchange Commission (SEC). These oil shale reserves, unlike those discussed in my testimony, meet the definition of proved reserves—they are developed

or are being developed and they are economic with current prices and existing technology.

While SEC rules state that oil shale (along with coal and gilsonite) should not

generally be classified as a proved oil and gas reserve, it leaves open the possibility

of doing so if markets develop and companies demonstrate commitment to develop

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the necessary production. For example, the SEC and EIA have both recognized large

amounts of coalbed methane as proved gas reserves. EIA will recognize a larger portion of the oil shale resource base as proved reserves when and if it is developed

and meets the definition for proved reserves.

Environmental Impact

Question 5. Your testimony stated ‘‘it will be important for existing technologies to

improve from an efficiency, and environmental impacts perspective.’’ You also

state that ‘‘the environmental impacts of shale oil development are significant.’’

How can DOE make these statements if it has not performed an environmental

impact statement on oil shale production? Isn’t it possible that the impacts could

be mitigated to a point where they might not be ‘‘significant’’?

Answer 5. As there has never been a full-scale operational oil shale development

in the United States, there need to be technological advances to improve the effectiveness and efficiency of the industry. The environmental impacts are no greater

than other very large industrial developments, such coal mining and petroleum refining operations, but they are significant. These are very large mineral extraction

and upgrading operations, with all of the environmental issues and problems associated with that kind of development. Due to the significant amount of energy currently required to extract a useful product from oil shale, it is also likely that net

greenhouse gas emissions from oil shale production will exceed that of conventional

fuels.

Greenhouse Gases

Question 6. You also stated that ‘‘greenhouse gas emissions will be released when the

fuel (shale oil) is consumed.’’ How would these emissions be different from consumption of conventional oil?

Answer 6. In assessing the overall greenhouse gas impact of oil shale, it is necessary to look at the complete production/consumption cycle. Oil shale production—

whether through surface retorting or an in situ process—is substantially more

energy-intensive than conventional oil production. Assuming fossil fuels are used to

provide the energy input for oil shale production, the net greenhouse gas impact of

developing oil shale resources is likely to be substantially higher than the per-unit

impact of convention oil production. The production of greenhouse gasses will vary

by the technology employed. The use of low temperature conversion in in situ

processes will reduce greenhouse gas emissions.

For most surface retorting operations the level of green house gases released from

the ground during development, will likely be very similar to emissions resulting

from the production of conventional oil. It should be noted, however, that very high

temperature retorting processes (i.e. direct combustion) could generate higher

amounts of carbon dioxide. Western oil shales are rich in carbonate compounds,

which when combusted will release carbon dioxide. It is likely the application of indirect heat and slower heating rates, as are currently being employed in small operations, will help minimize these increased carbon dioxide emissions. Elevated carbon

dioxide emissions are not anticipated from in situ production. Again, the rate of

heating and the low temperatures (relative to direct combustion) avoid conversion

of carbonate compounds to carbon dioxide.

The liquid fuels produced from western shale oil will be low in sulfur and rich

in hydrogen that when consumed will produce less carbon dioxide per unit of energy

than conventional fuels.

Energy Requirements

Question 7. One of the issues sometimes raised is one of energy requirements for producing oil shale, which is central to sustainability. Does your agency have any

analysis of energy requirements? What needs to be done to reduce the energy costs

of production?

Answer 7. How much energy is consumed in the production of energy is usually

described as the energy balance. The oil shale industry has often been criticized for

consuming large amounts of energy in the manufacture of the output energy. Shell

Oil reports that in their ICP In situ process they consume 1 Btu for every 3 Btu’s

of energy produced. This ‘‘energy balance’’ is substantially lower than for many

other fuel sources. However, the utilization of natural gas produced during the ICP

in situ process doubles the energy efficiency to 6 btu’s of energy produced for each

btu consumed. One of industry’s primary goals is to increase this energy balance,

which would both improve the economics of oil shale production and reduce its environmental impact, particularly in terms of net greenhouse gas emissions. There are

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also opportunities to improve energy balances once pilot and demonstration plants

are running.

Task Force

Question 8. How do you propose that DOE engage industry, local communities and

other stakeholders in program planning efforts? Would you support the tri-agency

Task Force concept advanced by Senator Hatch?

Answer 8. The Budget does not include funds for an oil shale program and the

Administration isn’t pursuing a new program promoting the development of oil

shale.

Mr. GIBBONS. Thank you very much, Secretary Maddox. Again,

your testimony is very helpful to the Committee, and we certainly

appreciate your presence here before us today.

We will turn now to Mr. Chad Calvert, Deputy Assistant Secretary, Land and Minerals Management, U.S. Department of the

Interior. Secretary Calvert, welcome back to the Committee once

again. It is a pleasure to see you before us, and the floor is yours.

STATEMENT OF CHAD CALVERT, DEPUTY ASSISTANT

SECRETARY, LAND AND MINERALS MANAGEMENT, U.S.

DEPARTMENT OF THE INTERIOR

Mr. CALVERT. Thank you, Mr. Chairman. I appreciate having the

opportunity to testify today on behalf of the Department of the Interior and the Bureau of Land Management, which is a part of

Land and Minerals Management at the Department.

Let me start out by saying that the Secretary has taken a real

interest in the issue, and she recognizes that we are at a very

unique time, with oil around $60 a barrel and technology evolving

across the world for development of oil shale. She recently visited

eastern Utah and western Colorado and actually went out and

looked at some of the development that is going on on private lands

there; and was very encouraged by the technology and the development of it; and has encouraged BLM to move forward as quickly

as they can to develop commercial leasing.

I will speak about BLM’s role here as the land manager, the land

and resource manager, and our responsibility to manage public

lands for multiple use; which includes, of course, the development

of oil shale.

On Federal lands in Wyoming, Utah, and Colorado, we have

roughly 72 percent of the surface oil shale reserve, and as much as

82 percent of the Nation’s reserve in those three states on Federal

land.

The BLM currently has no commercial leasing regs. They developed drafted regs in the 1980s in response to high prices. And after

the 1974 oil shale prototype program had begun, BLM decided, in

roughly ’83, not to complete those regs, because technology and

prices just weren’t keeping up with enabling development of oil

shale, and they abandoned the regulatory process at that time. And

there has been no industry interest in redeveloping regs since the

early ’80s, until now.

Currently, the President’s national energy policy outlined recommendations for the BLM to diversify and increase energy supplies, which included development of oil shale. BLM developed a

plan containing 54 discrete tasks designed to implement the

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President’s directives. And one of those was to establish an Oil

Shale Task Force to develop recommendations for the BLM on how

we should move forward.

The Oil Shale Task Force was designed to address four points: how to access unconventional resources on public lands; to identify

impediments to oil shale development; to coordinate and combine

for public land managers what industry interest was in research

and development of commercial opportunities on public lands; and

to provide Secretarial options to enable us to capitalize on the opportunities. The task force has a draft report which is being finalized and, hopefully, we can provide to this Committee expeditiously. On November 22, 2004, BLM, on a recommendation from the

task force, proposed an oil shale lease form and a request for information to solicit comments on an initial oil shale leasing program.

Ninety percent of the comments were favorable to developing a research, development, and demonstration program. On June 9th, just roughly three weeks ago, we finalized regula- tions in the ‘‘Federal Register,’’ requesting nominations for

RD&D—which is research, development, and demonstration activities—and requested industry to supply or to nominate potential research parcels within the next 90 days, until September 7th. This program would allow tracts of land up to 160 acres to be used to demonstrate the feasibility of technologies. The lease terms

would be ten years, with an option to extend for five years on a

showing of diligence of research. Royalties would be waived during

the lease, and rentals would be waived for the first five years. Applicants would also at the time of the nomination be able to

identify an additional 4,960 acres that they would have a preferential right to lease, on the showing of commercial development

on the 160-acre lease.

One of the principal reasons we decided to move forward with

the RD&D lease program was because we really lacked the ability

to do more extensive or comprehensive NEPA on technologies that

we didn’t know would be utilized in areas that we didn’t know

would be located. And we decided that it was better to move forward with small scale; determine what could be done using an environmental assessment tiered to the land-use plan; and then,

based on what was developed as part of that 160-acre lease, move

forward with additional NEPA in the future that would enable

commercial development in a way that was appropriately covered

by the National Environmental Policy Act. I will close by saying we are committed to developing a commer- cial leasing program, and we believe that what we have proposed

is the best way to go about doing that. Thank you, Mr. Chairman. [The prepared statement of Mr. Calvert follows:]

Statement of Chad Calvert, Deputy Assistant Secretary for Land and Minerals Management, United States Department of the Interior

Mr. Chairman and Members of the Committee, thank you for the opportunity to appear here today to discuss the Bureau of Land Management’s (BLM) efforts to

facilitate and promote oil shale research and development on public lands.

America faces an energy challenge. As recently as April 5, 2005, Federal Reserve

Chairman Alan Greenspan commented extensively on this challenge. He stated,

‘‘Markets for oil and natural gas have been subject to a degree of strain

over the past year not experienced for a generation. Increased demand and

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lagging additions to productive capacity have combined to absorb a

significant amount of the slack in energy markets that was essential in containing energy prices between 1985 and 2000.’’

For a considerable time, many have believed that oil shale, if economic, has the

potential to be a major source of domestic energy production, especially since it is

suited for refinement as jet fuel for the military and the airline industry. Recently,

the BLM, which has the authority to issue leases for oil shale under the Mineral

Leasing Act and to receive rental payments and royalties, has received expressions

of interest from industry for conducting research and development projects on public

lands in the Green River Formation in the tri-state area of Colorado, Utah and Wyoming. It is BLM’s hope that renewed interest in oil shale research and development

efforts will lead to environmentally responsible ways of unlocking the vast oil shale

resources contained in the United States, and presents a potential means of helping

to reduce the imbalance in domestic energy consumption and production that currently exists in this country.

Background

Oil shale is a type of rock formation that contains large concentrations of combustible organic matter. When processed, oil shale can yield significant quantities of

shale oil. Various methods of processing oil shale to remove the oil have been developed. A common element among those methods is the use of heat to separate out

the oil from the rock.

The United States has significant oil shale resources, primarily within the Green

River Formation in Wyoming, Utah and Colorado. These oil shale resources underlie

a total area of 16,000 square miles and represent the largest known concentration

of oil shale in the world. Federal lands comprise roughly 72% of the total oil shale

acreage in the Green River Formation.

In the latter years of World War II, several tests were conducted to determine

the economic viability of oil shale extraction technologies. However, in the years following World War II, petroleum producers looked to more easily accessible and economically viable supplies and interest in oil shale extraction declined. More recently, during the mid 1970s through the late 1980s, the Department of the Interior

and the BLM made oil shale resources on public lands available through the Oil

Shale Prototype Program, which was designed to allow companies to develop and

refine the technology for extracting oil from oil shale. Additionally, in the 1980’s,

the U.S. Geological Survey (USGS) had an active oil shale mapping program, which

mapped the major oil shale fields of the United States and conducted geological research on the Green River deposits. The USGS also conducted mineralogical and

geochemical studies aimed toward characterizing oil shale for the commercialization

of this resource.

Precipitated by the oil price spikes of the early 1970s, companies showed significant interest in exploring domestic oil shale development. Previous oil shale research showed that it was possible to extract shale oil from the rock; however, despite government subsidies, the extraction process was energy-intensive and costly.

Through a series of experiments, industry attempted to find more effective ways to

extract shale oil from oil shale rock, but the easing and subsequent collapse in petroleum prices led the companies to conclude that production was not economically

viable. The participants in the Oil Shale Prototype Program withdrew from their research efforts before the BLM could promulgate permanent regulations for oil shale

leasing and operation.

Most USGS activities related to this commodity have also diminished significantly. However, since the latter half of the 1980s, the USGS has maintained a

small effort in oil shale studies, both domestically and abroad, which included evaluation of world oil shale resources and a cooperative effort funded by the Department of Energy to create a National Oil Shale Database, in which shale oil analyses

and other data were entered and compiled. With the recognition that oil shale is

a potentially important domestic fossil energy resource, the USGS has continued in

these efforts to the present day. Although no comprehensive oil shale assessment

has been done, the USGS has completed oil shale resource studies on some of the

most promising areas. One example of this is ‘‘Thickness, oil-yield, and kriged

resource estimates for the Eocene Green River Formation, Piceance Creek basin,

Colorado’’ USGS Oil and Gas Investigations Chart OC-132. Another example is

USGS Open-File Report 91-0285 ‘‘Oil-Shale Resources of the Mahogany Zone in

eastern Uinta Basin, Uintah County, Utah.’’ USGS is currently working with the

State of Utah to evaluate all oil shale lands in the eastern Uinta Basin, compiling,

among other things, geologic maps, cross sections, geophysical and lithologic logs,

and drill hole information.

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Elsewhere in the world, efforts continue to harness oil shale resources. For example, in Gladstone, Queensland, Australia, there is a large-scale demonstration

project where, from June 2001 through March 2003, 703,000 barrels of oil, 62,860

barrels of light fuel oil, and 88,040 barrels of ultra-low sulphur naphtha were produced from oil shale. In January 2003 alone, the operation produced 79,000 barrels

of oil. Significant oil shale reserves also exist in the Republic of Estonia, where active oil shale deposits amount to about 9.2 billion barrels of oil.

Current BLM Efforts

The President’s National Energy Policy outlined a number of recommendations to

diversify and increase energy supplies, encourage conservation, and ensure environmentally responsible production and distribution of energy. In response, the BLM

developed a plan containing 54 tasks designed to implement the President’s directives, including efforts to promote the development of oil shale resources on the public lands. To carry out this task in an environmentally responsible manner, and in

keeping with our multiple-use mandate, the BLM established its own Oil Shale

Task Force.

The Oil Shale Task Force was established to address: 1) access to unconventional

resources (such as oil shale) on public lands; 2) impediments to oil shale development on public lands; 3) industry interest in research and development and commercial development opportunities on the public lands; and; 4) Secretarial options

to capitalize on the opportunities. The Task Force has prepared a report concerning

the development of oil shale resources on Federal lands in order to determine

whether technological advances have reached the point where it is possible to develop those resources economically and in an environmentally responsible manner.

On November 22, 2004, the BLM published a proposed oil shale lease form and

request for information in the Federal Register to solicit comments and suggestions

from interested parties about the design of the oil shale leasing program. The report

recommendations and BLM’s analysis of the responsive comments to the Federal

Register notice led to the design of an Oil Shale Research, Development and Demonstration (RD&D) program.

BLM published a new, final oil shale lease form in the Federal Register on June

9, 2005, and invited interested parties, from June 9, 2005 through September 7,

2005, to nominate public lands for oil shale RD&D activities. The nominations must

be accompanied by a non-refundable application fee of $2,000. The RD&D lease program design allows tracts of land up to 160 acres to be used to demonstrate the

economic feasibility of today’s technologies over a lease term of ten years, with the

option for an extension of up to five years. The payment of royalties will be waived

during the RD&D lease, payment of rental will be waived for the first 5 years of

the RD&D lease, and an applicant may identify up to an additional contiguous 4960

acres that it requests be reserved for a preference right commercial lease should

RD&D efforts prove successful in demonstrating the economic feasibility of oil shale

production.

One of the principal reasons to offer small RD&D leases before issuing commercial

leases for oil shale is to obtain a better understanding of the environmental effects

of the new technologies and the effectiveness of various mitigation measures. Consequently, given the small scale of the RD&D leases, BLM has determined that for

environmental review under NEPA, site-specific environmental assessments (EAs)

would be more appropriate than a programmatic environmental impact statement

(EIS) document. The complexity of the analysis required for the RD&D lease will

depend on the location, the type of project proposed, and the type of technology to

be used.

Conclusion

Thank you for the opportunity to testify today about the BLM’s Oil Shale Development efforts. I would be happy to answer any questions you have.

Response to questions submitted for the record by the Bureau of Land

Management, U.S. Department of the Interior

1. Question: What are the three most important things that the Federal Government

can do to ensure timely production of large volumes of oil from oil shale?

Answer: The Department of the Interior believes three things must happen before commercial oil shale production will take place: 1) oil shale resources must be

made available for research and development of extractive technologies; 2) extractive technology must be improved to increase efficiencies while minimizing environmental impacts, and 3) a market for oil shale end products must develop.

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The Department of the Interior’s Bureau of Land Management (BLM) has taken the first step by making Federal oil shale resources available through the BLM’s

recently-created Research, Development and Demonstration (R,D&D) leasing program. In addition, the BLM will promulgate permanent leasing regulations in accordance with the recently-signed energy bill. The BLM’s R,D&D leasing program makes it possible for interested parties to pro- ceed with the second step of improving extractive technologies. In light of current

market prices for crude oil, private companies should have ample incentive to conduct R,D&D and improve their oil shale technology. The final step, development of a market for the end products, will ultimately de- pend on the economic viability of oil shale.

2. Question: On April 12, 2005, Mr. Tom Lonnie from the BLM testified before the

Senate Committee on Energy and Natural Resources that BLM has not examined

the Canadian program that has led to the production of large quantities of oil

from oil sands. When will the Department conduct an analysis to learn the significant features that made their program a success?

Answer: The BLM intends to examine and evaluate the Canadian experience and

process to see if there are lessons we can learn and apply to our unconventional

resource development efforts. However, it is important to note that oil sands and

oil shale are distant resource cousins and there are vastly different economic and

technological challenges associated with developing these resources. Any formal

analysis of the Canadian oil sands program is beyond the mission of DOI.

3. Question: Your testimony mentioned the June 9 Federal Register notice on RD&D leasing. The Subcommittee will present questions to you about this leasing proposal to be answered as part of the record. Generally, we have some concern about

the lack of specificity about several very important aspects such as the price for

companies to receive a commercial lease on the preference right acreage, the

royalty and regulatory schemes that will apply to production and activities on the

leases, and other important provisions. Could you provide more details NOW on

these items?

Answer: The BLM expects to develop a methodology for determining fair market value for bonus bids to convert a R,D&D lease to a commercial lease, including any

preference right acreage. However, the data currently available on oil shale that

could be used to determine fair market value is very limited and unreliable. Also,

the R,D&D program is designed to allow the demonstration of new technology where

the economics are not fully understood at this time. What is known at this time is

that conversion would be based on the ability of the lessee to produce commercial

quantities of shale oil from the lease, documentation of consultation with state and

local governments on the mitigation of socio-economic impacts, and the BLM’s determination, following NEPA analysis, that the environmental consequences of developing the preference right area are acceptable.

The BLM expects to gather more reliable data from the R,D&D leases. The Secretary has the authority under the Mineral Leasing Act to establish royalty rates,

and plans to do so prior to the commencement of commercial production. The goal

of the BLM is to promulgate final commercial leasing regulations prior to the conversion of R,D&D leases to commercial leases, incorporating the establishment of

royalty rates as an integral aspect of the final rulemaking

4. Question: Would you agree that the 5120 acre limit and the one lease per lessee

restriction of the Mineral Lease Act of 1920 are impediments to commercialization

of oil shale? Would you agree that removing these restrictions would be an important step toward commercialization?

Answer: The BLM is aware of assertions that the 5120 acre limit could constitute

an impediment to commercial oil shale development. However, with the enactment

of H.R. 6, the Energy Policy Act of 2005, the per 5120 acre limit has been increased

to 5760 acres and the number of acres a lessee may hold in any one state has been

increased from 7680 acres to 50,000 acres. These changes should have a positive impact on commercialization efforts. However, until oil shale development proves to be

economic and moves beyond the RD&D phase, these limitations should have little

practical impact on commercialization efforts.

5. Question: In Utah, and possibly Wyoming, prospective developers now need to deal

with more than one agency to put together a logical development unit? Would land

exchanges designed to block up logical development units help solve this impediment?

Answer: Oil shale deposits, like other natural resources, occur on Federal, State,

Indian, and private lands. As a result, developers may need to deal with more than

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one agency to assemble a logical development unit It should be noted, however, that

through Section 369(n) of the recently-enacted Energy Policy Act of 2005, Congress

has directed the Secretary to consider using land exchanges where appropriate and

feasible to consolidate land ownership and mineral interests into manageable areas.

This provision directs the Secretary to identify public lands containing oil shale or

tar sands deposits within the Green River, Piceance Creek, Uintah and Washakie

geologic basins and to give priority to implementing land exchanges within these

basins.

6. Question: You testified that the BLM owns about 72% of the Resource acreage,

with the remaining acreage is held by non-federal interests. Holders of these other

28% may wish to nominate federal lands under your recent Call for Nominations—Oil Shale Research, Development and Demonstration (R, D, and D) Program contiguous to their non-federal holdings. Is there anything in your process

that would prohibit a holder of non-federal lands from conducting their R, D and

D activities on non-federal lands and qualify the nominated BLM property for

conversion (subject to the conversion requirements in your regulations) at a later

date? It would appear that cases like this would improve the likelihood of commercialization, which is the goal. Do you agree?

Answer: The process established by the BLM does not prohibit those conducting

oil shale research and development on private lands from applying for a Federal

lease. The criteria for nominating and qualifying for a preference right lease are set

forth in the June 9, 2005, Federal Register notice. In order to qualify for conversion,

the applicant would need to produce shale oil in commercial quantities from the

Federal lease before its expiration.

7. Question: You testified that NEPA requirements are a reason why progress has

been slowed in preparing lease regulations. Uncertain permitting timelines also

put investment at risk, and are an impediment to investment. Do you have any

suggestions for Congress to mitigate these impediments? For example, if Congress

were to supply the financial resources for BLM to work with applicants to assure

that applications are complete upon first submittal, would that help? Can Congress help eliminate indefinite delays by placing limitations on timeframes for

protests? What about reducing or eliminating NEPA requirements below a certain

impact level?

Answer: Conducting NEPA analysis does take time. In complicated projects, Federal law also brings into play numerous other environmental statutes, such as the

Endangered Species Act, the Clean Air Act, the National Historic Preservation Act,

etc. We note that the Energy Bill contains a provision in Section 369(k) that designates the Department of the Interior as the lead Federal agency for coordinating

applicable Federal authorizations and environmental reviews and directs the Secretary to issue regulations necessary to implement this provision within six months

of enactment.

The immediate challenge for the oil shale program is that it is unclear what the

proposed actions of commercial leasing would be, given that we do not yet have proposals for commercial projects. For this reason, and at this time, BLM would prefer

to conduct site-specific NEPA analysis instead of doing a regional programmatic environmental impact statement (EIS) document.

One of the principal reasons to offer small research and development leases before

issuing commercial leases for oil shale is to obtain a better understanding of the environmental effects of the new technologies and the effectiveness of various mitigation measures. As stated in the call for nominations, the complexity of the analysis

required for the R,D&D lease will depend on the location, the type of project proposed, and the type of technology to be used. It is anticipated that more intensive

NEPA analysis will be performed before the award of a preference right lease, using

information generated during the R,D&D phase. Approval of conversion to a commercial lease would then also depend on a determination that a commercial operation on the acreage selected could be conducted in an environmentally acceptable

manner.

The BLM works closely with industry to ensure that the required information is

provided prior to the submittal of any application for a use authorization. This helps

to eliminate potential delays due to incomplete applications. In addition, the BLM

is performing full and meaningful consultation with the public, particularly with

local individuals through the land use planning process and other project-specific

NEPA analysis. The BLM is also working on creating more effective governmental

partnerships, through the lead agency-cooperating agency relationship and its application to the planning and associated environmental assessment responsibilities.

This will help the BLM to work together and foster a commitment by local, tribal,

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and state governments and other Federal agencies to recognize common goals and

achieve balanced resource management.

The BLM has existing authority to limit protest periods, and this is among the

options the BLM will be considering in drafting the final commercial leasing regulations. However, there are pros and cons to limiting protest periods, and BLM will

need to weigh both in making any final decision to impose such limitations.

8. Question: Mr. Calvert, it is my understanding that Shell’s in situ conversion

process, even though based on heating the ore underground, involves nearly 100%

surface disturbance, removing all vegetation and disturbing the soil. If BLM approves a plan to allow this, how would DOI ensure that the inevitable and significant damage to the land be reduced so that others would be able to use the land

after mining is through?

Answer: The BLM anticipates that the proposed R,D&D program will include

some level of surface disturbance, regardless of the methodology employed. The in

situ conversion process involves drilling vertical holes, as is done in oil and gas recovery, but does not have any mining component. The in situ process, like any other

major operation, is expected to disturb a portion of the surface of the lease parcel

at any given time. As with many oil and gas technologies, one might expect a reduced surface impact over time as in situ evolves into second and third generation

technology. The R,D&D program is designed to require a phased reclamation approach. First, there will be intermediate reclamation of disturbed areas when those

areas are no longer needed in the ongoing operations. As the operation terminates,

the disturbed area of the lease is to be fully reclaimed before the lease bonds are

released.

The BLM recognizes that the complexity of the NEPA analysis will depend on the

site selected, the type of project proposed, and the type of technology to be used.

The BLM will use the NEPA process to analyze the impacts to the land surface,

vegetation, soil, underground water, air, surface water and fisheries and identify

mitigation strategies to minimize adverse impacts. Additionally, as shown in the

June 9th Federal Register notice, prior to conducting operations on the leased land,

a lessee must submit a plan of operations that will include a description of best

management practices for interim environmental mitigation and reclamation.

9. Question: Although industry is touting some new innovations, their approaches to

oil shale production still involve a major mining operation. What specific techniques and precautions will DOI require to ensure protection of surface water and

ground water from depletion and contamination, to protect topsoil stability, and

to control air pollution from that mining?

Answer: Prior to the award of any lease, the BLM will conduct a NEPA analysis

to determine that this protection is possible at the site using the proposed technology. Under the R,D&D program, a lessee will be required to submit a bond sufficient to cover actual expenses associated with total reclamation and abandonment

prior to the issuance of a lease. The amount of the bond will be estimated based

on the technology to be used and projected disturbance associated with such technology. Also, a lessee must submit an annual plan of operation to be reviewed and

approved by an appropriate BLM official, subject to reasonable modifications to assure protection of the environment. Furthermore, a lessee will be required to provide an interim reclamation plan under which the lessee will be required to continuously reclaim disturbed portions of the lease as soon as such areas are no longer

needed for operation.

Mr. GIBBONS. Thank you very much, Secretary Calvert. Again,

the Committee appreciates your presence and the testimony here

today.

Before we turn to questioning and answering of the Committee

and interaction with the panel, a couple of housekeeping requirements. What I would like to do is ask unanimous consent to submit

for the record the opening statement of Mr. Grijalva, the Ranking

Minority Member, which will be done without objection.

[The prepared statement of Mr. Grijalva follows:]

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Statement of The Honorable Rau ́l M. Grijalva, Ranking Democrat,

Subcommittee on Energy and Mineral Resources

Today’s hearing again focuses on a potentially untapped, domestic energy

resource—oil shale and oil sands.

As I noted last week, while industry experts say oil shale holds great potential

with an estimated 2 to 4 trillion barrels of oil locked in the Green River formation

out west, it has a history in the western United States that is shaky at best. Many

bold promises have been made in the past about oil shale’s potential and about the

affordability of its production but few of them have been realized so far.

It is important that we get clear facts about oil shale’s fuel potential and about

new methods for its production and that we are honest about analyzing and discussing those facts. We often hear, for example, that the United States currently

consumes almost 20 million barrels of oil a day. Saudi Arabia now produces roughly

11 million barrels a day. If, as Chairman Gibbons suggested last week, this country

could produce 60 percent of its oil needs from oil shale and tar sands, that would

essentially mean equaling the current Saudi production figures, with much of it

coming from Western Colorado.

However, as the Colorado newspaper, the Grand Junction’s Daily Sentinel, editorialized on June 26, ‘‘No one who values the West’s open spaces, wildlife and natural

landscapes—in short, most Coloradans—would want to see a major swath of northwestern Colorado turned into a vast industrial zone that would make the likes of

Gary, Indiana, look like a garden spot. To build the sort of oil-shale industry [Chairman] Gibbons envisions, the Rocky Mountain West as we know it today would have

to be torched along with the shale itself.’’

So, we need to be careful about claims and projections and keep them in perspective.

Research phases need to examine not only ways to improve the technical aspects

of oil shale production, but also the environmental consequences that could come

from commercial operations. We need to know what damage an expanded industry

could do to the water, air, scenic beauty, and recreation opportunities of the West

and put in place the technical refinements and restrictions that reduce that damage.

Finally, as I stressed last week, with oil trading at $50 to $60 a barrel, and as

evidenced by Shell’s success in developing oil shale, Congress should not underwrite

domestic oil shale development. The BLM proposal to lease tracts of public land for

research and development is unobjectionable. But, American taxpayers do not need

to subsidize oil shale development.

Mr. GIBBONS. And we also want to ask unanimous consent to

submit for the record two publications from the Department of

Energy: Volume One, dated March 2004, and Volume Two, dated

March 2004; titled ‘‘Assessment of Strategic Issues,’’ for Volume

One, and Volume Two is ‘‘Oil Shale Resources Technology and Economics,’’ for the record. That will be done, without objection, as

well.

[NOTE: The information submitted for the record has been

retained in the Committee’s official files.]

Mr. GIBBONS. Let me begin, perhaps, with Dr. Barna over there.

The issue of the Department of Defense and its role in assisting

with or encouraging the development of oil shale products is primarily restricted not to technology, but to assessment of the product that is produced from whatever technology or whatever source

of that.

Will there be interaction between DOD and our research and development and demonstration programs that the Department of Interior is proposing, as we go through the next ten years, to find the

best or most suitable, not just product, but process by which we get

product to the commercial? Will there be coordination?

Dr. BARNA. Absolutely. We intend to work with the Department

of Interior, the Department of Energy. As you say, our primary role

is to certify, to categorize, to help in the setting of specifications.

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But this has to be done as a group process. It’s just not going to

be done in isolation; because our overall goal is to provide the catalyst for them to then develop an industry.

Mr. GIBBONS. Describe your process. What is it that you actually

do when you get a product into your lab?

Dr. BARNA. Well, what we do is we actually run it on jet engines;

we run it on diesel engines. We carefully monitor the energy inputs

and outputs, and the particulate matter—NOXs and LXs, and

when appropriate, SOXs. And we grade it.

And then we look at ways that we can change or improve specifications. One good example is—this is a recent experience with

Fischer Tropsch fields. We may be able to change the specifications

so that we get one fuel that does both jet and diesel. This helps

industry, as well as helps us, because now we have one less fuel

on the battlefield that we have to manage.

Mr. GIBBONS. Sure.

Dr. BARNA. So it is in the area of specifications, as well. So that

is, I think, the area where we will have the best impact.

Mr. GIBBONS. Hopefully, we have provided a sample of what was

provided to us from Oil-Tech, of products that come from oil shale,

and the production of fuels. I presume that each of these products

that you see up there, except for the waste rock after the oil has

been removed, is a product that comes to you for that sort of testing.

Dr. BARNA. We would get the finished—we are interested in the

finished fuel products. So we would be interested in the JP-8-like

product or the——

Mr. GIBBONS. Diesel.

Dr. BARNA. Or the diesel product, exactly. And so sometimes we

forget that there is a difference between what comes out of the

ground and the finished product that goes into the machine. And

our interest there is in that machine.

But we are very interested that they are all fit for use. So the

jet fuel is jet fuel to the user. He doesn’t really care if it comes from

shale, biomass, oil, whatever; it’s fit for his use. So that is where

we would get very heavily involved.

Mr. GIBBONS. Secretary Maddox, has the Department of Energy

performed an analysis of whether production of oil shale is economic?

Mr. MADDOX. That is part of the construction economics. We

have looked at the numbers. And I think one of the things we have

looked at is understanding the difference between profit versus

competing investment alternatives. Right now, in this price range,

yes, I would say oil shale is economic.

Mr. GIBBONS. Well, my question was, you are giving me your

opinion.

Mr. MADDOX. Yes.

Mr. GIBBONS. Has the Department officially analyzed it and

reported on the economics of it?

Mr. MADDOX. We have analyzed it. I don’t know whether we have

published those analyses. We will be happy to supply them to the

Committee. But we have looked at the comparative costs of oil

shale with other products in the market.

107

Mr. GIBBONS. And I assume this analysis would be with current

technology?

Mr. MADDOX. Yes.

Mr. GIBBONS. Secretary Calvert, what are the three most important things that your Department and the Federal Government can

do to assist in expediting the development of oil shale, or oil sands,

or unconventional oil sources in this country?

Mr. CALVERT. I can speak on behalf of the Department of Interior. And as far as the rest of the Government goes, I’m not sure

that I am qualified to say what DOD or DOE can best be doing to

help.

But for the Department of the Interior, I feel, as the land managers here, it is our duty and responsibility to provide adequate

NEPA coverage for development; to ensure that our land use plans

under FLPMA are properly amended or supplemented; and then to

process permits in a timely way and ensure that there is monitoring that goes along with it, so that we don’t get snagged in legal

battles.

Mr. GIBBONS. My time has expired. We will turn to Mr. Pearce

for questioning. Mr. Pearce?

Mr. PEARCE. Thank you, Mr. Chairman. Mr. Maddox, we had a

witness last week who said he could withdraw oil from shale for

$18 to $24 a barrel. Do you believe that is possible?

Mr. MADDOX. That is probably an optimistic number. I would

probably guess a little bit higher. Probably, at the $20 range would

probably be fair, out of the ground.

Mr. PEARCE. And at the $20 range, why are we not doing it? Oil

is at a $60 range.

Mr. MADDOX. Well, the fundamental economics are that you can

get a lot of other oil out of the ground cheaper. And if you look at

most corporate planning numbers, they look at a market price of

$18 to $20 as kind of what most people are using for a planning

number.

Most investment decisions are based on an historical average

price, which I think now is just moving to $20 for a lot of companies. And so while people say, ‘‘OK, we can get it out of the ground

for 20,’’ that means a market price closer to 25, high 20s. And that

does not work on an internal planning number for most corporations when they decide where to expend the money.

Mr. PEARCE. Do you think we don’t have any entrepreneurs out

there willing to risk? Right now, the margin is 40 bucks. You risk

20, and you make 60. From a business perspective, you don’t find

those kinds of rates of return. Why don’t we have any takers?

Mr. MADDOX. Well, to compare the capital costs, you have a

$70,000-per-barrel capital cost for oil shale, versus about a $33,000-

per-barrel cost in oil sands, for instance. So there is a significant

capital barrier. And so now you need an option in order to take a

risk.

Mr. PEARCE. Does your estimate of cost—20, 25, or something in

that range—include capital costs?

Mr. MADDOX. That’s production cost.

Mr. PEARCE. Just production cost?

Mr. MADDOX. Yes.

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Mr. PEARCE. So you mentioned in your written testimony that we

should be able to squeeze out 2 to 3 million barrels a day, if we

were able to access our resource and use it properly. How many

acres would it take to get that kind of production?

Mr. MADDOX. I’m trying to remember that number. Basically, we

are looking at 10,000 square miles.

Mr. PEARCE. Ten thousand square miles?

Mr. MADDOX. Yes.

Mr. PEARCE. To get that kind of production? And is that at 30

gallons per ton? How many tons do you get off of an acre?

Mr. MADDOX. At maximum concentration, we can get approximately 2-1/2 million barrels per acre.

Mr. PEARCE. So 2-1/2 million?

Mr. MADDOX. Barrels of oil.

Mr. PEARCE. Say that again?

Mr. MADDOX. Two and a half million barrels of oil per acre, per

day.

Mr. PEARCE. Per what?

Mr. MADDOX. Per day.

Mr. PEARCE. No, I was asking about the number of tons of material per acre. In other words, you are saying you can get 2 to 3 million barrels a day out of shale oil. And I wonder how many acres

it is going to take to get that done. How many acres?

Mr. MADDOX. Yes, one acre.

Mr. PEARCE. You said 10,000. I am trying to verify that with the

number of——

Mr. MADDOX. Oh, for the——

Mr. PEARCE. Go ahead.

Mr. MADDOX. Well, we are looking to sustain this development

long term.

Mr. PEARCE. That is what I am looking at, too.

Mr. MADDOX. Yes. Yes.

Mr. PEARCE. We are not talking about——

Mr. MADDOX. Yes, we are looking at approximately a 300-millionbarrel—billion-barrel resource. So, I will have to, you know—let me

clarify those numbers. I will be happy to submit them for the

record.

Mr. PEARCE. I would like to find out the number. I would like

two or three approaches. You say it is going to take 10,000 acres,

and I would like some verification of that number. It is all I am

trying to get.

Mr. MADDOX. Yes. I will be happy to supply those.

Mr. PEARCE. It will require us to consider the number of tons per

acre of material that we are going to move. And to me, if we get

30 gallons per ton, that is not even yet a barrel per ton of material.

And we will kind of come back to that, if you could help give us

some documentation.

Mr. Chairman, I have other questions, but I will wait until the

next round. I see that my time has about expired.

Mr. GIBBONS. Mr. Pearce, let me explain from an engineering

standpoint that a ton of rock is literally pretty close to a cubic

meter worth of rock. So one cubic meter, you could get about a ton

of rock out of it. So that is probably this shale that is sitting right

in front of us.

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So a ton of material being that size, you would have to calculate

the depth, thickness of the formation, the extent, the length, all of

that. In an acre, if it is a 1,000-foot thickness, you can understand

how many tons you are going to get off that real quickly.

Mr. PEARCE. I can work with the rock——

Mr. GIBBONS. That is why I gave it to you, so you could have

something to do with that bright mind of yours besides sit here and

ask questions.

Mr. Cannon?

Mr. CANNON. Thank you, Mr. Chairman. The other interesting

thing about the size of a ton is that it equals about a barrel of oil,

I understand. So it is interesting calculations.

But let me ask you this question, Dr. Barna. Are you familiar

with the two technologies that have been presented? You have the

Shell in-situ process, where they heat the shale and draw off the

liquid; and then the, I don’t know, we call it the ‘‘Savage process,’’

essentially the old process but with some technical—do you happen

to know how much water is required in either of those processes

industrially? Are we talking about a significant amount of water?

Dr. BARNA. I do not, I am sorry to say. I am familiar with the

process of how Shell Oil is going to use the in-situ and the aboveground retorting. But I am not a process expert. I am more at the

consumer end of it.

Mr. CANNON. Thank you. Mr. Calvert or Mr. Maddox, do either

of you have a sense about how much water either of these

processes is going to take, on a per-barrel or other basis?

Mr. MADDOX. I am sure I have this here in my notes, if you give

me a second to dig through this. When we are looking for oil shale,

our production is probably 1 or 2 barrels of water for every barrel

of oil we produce. About two-thirds of that water, though, is dedicated to human resources, supporting people and infrastructure

around it. That is compared to oil sand production, which is about

2 to 4 barrels of water per barrel produced.

Mr. CANNON. Does that analysis distinguish between the in-situ

Shell process and the ‘‘Savage process’’?

Mr. MADDOX. It is generally considered approximately the same.

Mr. CANNON. OK.

Mr. MADDOX. From a planning standpoint. Somewhat, it is

geared to the offsite support mechanisms; not necessarily the

process.

Mr. CANNON. Do you have some documentation that analyzes

that, that utilization?

Mr. MADDOX. We will be happy to——

Mr. CANNON. If you have something, I would really very much

appreciate that.

Mr. MADDOX.—yes, submit it, in some form, either a question for

the record, it would be great, and we can just submit it through

there.

Mr. CANNON. Thank you. That would be perfect. Thank you very

much.

Dr. Barna, you were talking about coming up with a fuel, a single fuel that would meet two purposes. Can you just elaborate a little bit on what it would take for a diesel fuel to be equivalent to—

110

I think you were talking about jet fuel—for those two? Is that a

technically hard thing to do?

Dr. BARNA. We think it is possible. We have put out a draft specification to industry, and they are taking a hard look at that. We

have an excellent opportunity with the Fischer Tropsch type fuels,

because when they are recombined over a catalyst you can almost

do it boutiquely. You can add the number of carbons that you want

and the amount of branching.

So this just gives us the opportunity to look at what is available

and then, rather than using specifications or certifications that go

back to quite some time and tend to be patchwork, to look at the

possibility of issuing new specifications that could cover this.

Mr. CANNON. Would that be specifications for the engines or motors, or would that be specifications for the fuel itself?

Dr. BARNA. It would be for the fuel itself. Our goal is, we don’t

want an 18-year-old on the battlefield to have to make a decision

on—you know, if it is fuel for his vehicle, or her vehicle, it is going

to work, it is going to be fit for that purpose. But it may be the

same fuel that they are putting into a ship or an aircraft as well

as a tank.

Mr. CANNON. Well, you are familiar with the fractions that come

off naturally in the two processes. Are those fractions in the ballpark of the kinds of fuels that you are thinking in terms of?

Dr. BARNA. Well, I did that more of an illustration, sir, of, you

know, sort of looking forward to see if we can make this process

even better. We really haven’t got our hands on enough of the fuel

right now to do the testing we need to do. So as soon as that starts

coming off the line, we will do that. And just as in the case of coal,

we will look at reducing the number of fuels that the Department

of Defense has to use.

Mr. CANNON. How much fuel do you need coming out of this testing process, to get a sense of that?

Dr. BARNA. Well, we are getting very little right now. Just on the

Fischer Tropsch side, to do all the evaluation that we need, we are

talking somewhere in terms totally of about 20 million gallons.

Mr. CANNON. OK.

Dr. BARNA. And that is the bottom.

Mr. CANNON. Thank you, Mr. Chairman. I see my time is about

up. I yield back.

Mr. GIBBONS. Thank you very much, Mr. Cannon.

Let me also ask Secretary Calvert, with regard to the research,

development, and demonstration project acreage, the 160-acre limit

that you have out there, who decides on which acreage, or chooses

the acreage? I am sure that there is a variation in terms of quality

of oil shale that is out there, to make a determination. Who makes

the decision on which 160-acre parcel you get?

Mr. CALVERT. Well, that is correct, Mr. Chairman. There is a big

difference in the quality of the oil shale from place to place. And

what we have asked is for companies to come in and nominate the

160-acre parcels. We leave it to them to identify where the best

prospects are and to come in and nominate them.

Mr. GIBBONS. Is there a process by which they can go out and

evaluate these oil shale deposits, in terms of vertical thickness or

111

quality, without having to go through a long, torturous EIS

process?

Mr. CALVERT. Well, let me just check this, because what I am assuming is that they will be relying on previous USGS assessments

of what was out there. If you will give me just a moment, please.

[Pause.]

Mr. CALVERT. Yes. The assessment was done in the mid-’80s, and

they will be relying on that, is our assumption, to identify the highquality locations.

Mr. GIBBONS. Those were mostly surface examinations of the deposit; were they not?

Mr. CALVERT. They were done with core samples, maps, surface

identification, yes.

Mr. GIBBONS. OK. Where are you with regard to your commercial

leasing regulation of oil shale? Where is the process right now?

What is the expectation in terms of time to finish producing a regulation which will allow for commercial leasing of oil shale?

Mr. CALVERT. Congressman, we haven’t actually begun the rulemaking process for that. But the BLM is prepared, once we got this

rule out three weeks ago, to start this process. We estimate 18

months to two years for commercial leasing regs. The Department

has the authority, under the Mineral Leasing Act, to issue such

regulations, and we intend to move forward with that.

Mr. GIBBONS. When do you intend to move forward with it?

Mr. CALVERT. I can’t give you an exact date, but we would like

to move forward with it as soon as possible.

Mr. GIBBONS. Mr. Maddox, let me ask, if you in the Department

of Energy do your economic analysis of oil shale using current technologies, using current economic pricing index, and find that oil

shale is an economic resource, will that change the definition of the

resource to a proven reserve, once you have done your economic

analysis?

Mr. MADDOX. The definition of ‘‘proven reserves’’ actually is a Securities and Exchange Commission term. And that would have to

imply commercial development plans and expenditures are being

done on the property, and does not move to that point until production has actually started or the work toward production is started.

So from an SEC standpoint, it would take someone actually

doing work and committing resources to bring it into production.

From our standpoint, that’s a reserve that exists; it is there; it is

available. And the only thing preventing its development is the decision by someone to develop that resource.

Mr. GIBBONS. So if some company—say, Shell Oil Company—decides that its process is economically recoverable and that it wants

to engage in that, and you make an economic determination in

your publications—or you make that economic determination somehow—you would then see that if Shell is doing it economically,

then according to SEC—the Securities and Exchange Commission—terminology, that it would change——

Mr. MADDOX. Right.

Mr. GIBBONS.—the resource to a proven reserve oil base in this

country?

Mr. MADDOX. Correct. And that is one of the reasons why there

was a shift a year or two ago on the oil sands; that it was deemed

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as being developed and an appropriate level of private-sector development. So it was moved from an unproved reserve; which is why

such a huge jump in the reserves in Canada.

Mr. GIBBONS. You don’t see any obstacles with regard to environmental mitigation for development of this, do you, at this time?

Mr. MADDOX. Everyone understands that environmental issues

need to be addressed. And I have complete confidence that they can

be addressed.

Mr. GIBBONS. Now, getting back to my previous question, if I

may take just a minute beyond my time, because I think I want

to fully develop this idea about proven reserves, isn’t this exactly

what happened in the Canadian oil sands?

Mr. MADDOX. Exactly. It was not recognized as proven reserves

until about two years ago, when you kind of had critical mass of

investment.

Mr. GIBBONS. And did you have any involvement as the DOE

with regard to designating them as proven reserves once this

process took place?

Mr. MADDOX. No, we did not.

Mr. GIBBONS. So it was simply an industry regulation.

Mr. MADDOX. Right.

Mr. GIBBONS. Or an industry determination.

Mr. MADDOX. Uh-huh.

Mr. GIBBONS. All right. Mr. Pearce?

Mr. PEARCE. Thank you, Mr. Chairman.

Secretary Calvert, how long has your task force been going on?

When did it start?

Mr. CALVERT. I believe it was convened in 1993.

Mr. PEARCE. 1993?

Mr. CALVERT. Yes, sir.

Mr. PEARCE. In 1993, the price was about 18 bucks; and in 1999,

it eased down to 6 bucks. Now it is up to 60 bucks——

Mr. CALVERT. I’m sorry, 2003.

Mr. PEARCE. Oh, 2003?

Mr. CALVERT. Yes, sir.

Mr. PEARCE. In 2003, what was the price of oil?

Mr. CALVERT. Somewhere in the 20s, as I recall.

Mr. PEARCE. Now we are somewhere in the 60s. Do you have a

department in your agency that says, ‘‘You know, the price just

went from 20 to 60; can we accelerate this process?’’ Do you have

a department that does that?

Mr. CALVERT. Accelerate the task force?

Mr. PEARCE. Accelerate the concept that we are becoming every

day more dependent on oil; that the price of oil has the potential

to break the economy; and that you have a resource there that is

possibly—maybe not, but possibly—a source of great production.

And do you ever get a little more, ‘‘Pick up your feet just a little,

troops; let’s move a little bit more fast, because the price could be

100 as easily as it could be back to 20’’? Do you do that kind of

discussion?

Mr. CALVERT. Well, of course, we do that kind of discussion. I

have no doubt in my mind that there is commercially developable

oil shale that not only can be produced, but can be transported in

an economical way.

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Mr. PEARCE. Why do you not have a doubt about that? Because

right now, it appears you are even unwilling to take on the NEPA

process for the 4,900-acre tract, or whatever, on top of the 160. You

prefer to stay on the 160s.

Mr. CALVERT. Well, the problem with that is that we don’t have

any proposals. We have several different technologies out there,

and it is hard to do the NEPA without the proposals.

Mr. PEARCE. You don’t have any proposals right now to lease?

Mr. CALVERT. No, sir.

Mr. PEARCE. Lease land? Dr. Barna, does the fact that you are

investigating alternative sources for DOD—because I am sure you

are worried about national security and the availability. And in

your report you say you have 1.4 trillion barrels of oil available;

and yet you see the BLM doesn’t even have a request out there.

Does that make you wonder in the middle of the night if you really

have correctly evaluated how much oil is really available to us?

Dr. BARNA. Well, I think that it is available as a resource, sir.

Mr. PEARCE. No, no, but if it is an available resource, that means

we could go out and tap it. And yet, you see the process started

in 2003, and the price has gone from 20 to 60, and the process

hasn’t picked its pace up at all. It is going to continue wandering

on through this bureaucratic maze. And you say it is available, and

I am not sure it is.

Dr. BARNA. When I say it is available; potentially available. You

know, as soon as we can get it out of the ground. We have the

processes to do it. We have the resources, but——

Mr. PEARCE. No, you only have the resources when you have the

resources.

Dr. BARNA. When we have them. Right.

Mr. PEARCE. I have a desire to put a lot of money in the bank;

but until I get it there, the banker is not going to loan me a house

on it.

Secretary Calvert, you feel certain that when you get through

this 18 months to two years that the Chairman talked about, that

you will start leasing, if the plans were available?

Mr. CALVERT. Well, what we have is, we have land-use plans.

And we would like to be able to do environmental assessments to

those land-use plans for these 160 acres. They are much easier to

do. We don’t have to do full-scale EIS’s on something that we don’t

actually know at this point——

Mr. PEARCE. Now then, we go over to Mr. Maddox’s discussion

about the number of tons per acre.

Mr. CALVERT. Well, we don’t know. It could be the retort technology, it could be in-situ——

Mr. PEARCE. Is a 160-acre block economically viable?

Mr. CALVERT. Well, the economic viability is a commercial quantity of the available area, so it is a——

Mr. PEARCE. No, no, no, the economic viability—if I am drilling

an oil well, the economic viability is the cost of that oil well and

the amount of oil I can get out of it. And I am asking, is a 160-

acre tract, if that is what you are going to lease because the

NEPAs are a little bit difficult on the larger tracts, is a 160-acre

tract an economically viable number?

Mr. CALVERT. [No response.]

114

Mr. PEARCE. I think we probably should have an answer to that

at some point. And I guess my last question would be on this. So

we are going to go 18 months to two years, and we are going to

get this process for leasing. Why would I believe that this shale oil

is going to be any more available than natural gas, when the BLM

refuses to give leases in areas that have been previously drilled?

Again, I am trying to address the question of Dr. Barna there of:

Do we have enough fuel; do we have enough energy for our own

DOD requirements, our own defense? And I see the BLM unwilling

to give leases on natural gas. What makes me think that in a

process that is far more invasive, that we are ever going to even

lease one acre? Can you give me an answer to that?

Mr. CALVERT. I think that is a legitimate concern. I am not sure

exactly which BLM leases you are talking about, but the NEPA—

I hold no illusions. NEPA on oil shale will not be a simple process.

Depending on the technology, it could be very invasive, and depending on the location and the process that you go through. I

don’t anticipate it is going to be painless.

This is why, in order to expedite at least getting people onto

BLM land, we decided to use EAs, instead of going straight for a

full lease and have to do EIS’s; because then we would be in a twoyear process before they could ever even go out and start designing

their plans. And I share your concern. We intend to proceed as aggressively as possible.

Mr. PEARCE. My time has expired, but I want to get my staff to

give you exactly leases where the BLM in the Rocky Mountains is

not issuing APDs so that people can drill, in areas that have been

previously drilled. It is not like it is pristine. I will get you that

information.

In the meantime, Dr. Barna, you might look at powering those

airplanes and tanks with something else.

Mr. GIBBONS. Mr. Pearce, let me try to clarify your question

about the 160-acre and economic viability. The 160-acre is simply

for a research and demonstration project. It is not necessarily a determination. That 160-acre would be a limited amount for a commercial operation. It is there to determine whether or not the

process by which they are trying to develop under the RD&D principle is suitable. So you are right, 160 acres would not——

Mr. PEARCE. I think that, in effect, this is something that we

have to be aware of downstream. If the agency has got some concerns right now about NEPA processes, why are we saying this

stuff is available? It may not ever be touched. And we need to be

honest with ourselves if we are in this Committee hearing.

Mr. GIBBONS. I was only answering the question about the economic side of it before that. And there is an opportunity for extending the 160 acres.

Did you say 140, Mr. Calvert?

Mr. CALVERT. Up to the statutory maximum, which is 5,120.

Mr. GIBBONS. Five thousand, one hundred and twenty acres. All

right. Mr. Cannon?

Mr. CANNON. Thank you. First of all, let me just point out that

I love the idea of a ‘‘Department of Acceleration.’’ That actually

makes a lot of sense.

115

Following up on this, with the RD&D lease starting at 160 acres,

the cost of developing that, depending upon the depth and lots of

other things, could be very great. I mean, the operation in eastern

Utah, as I recall, was 200 or 300 million dollars, just to develop the

mine site. And you can hardly do that unless you are pretty sure

you are going to go way, way beyond 160 acres.

Mr. Calvert, does that 160 acres relate also to the Shell process,

where they are looking at a section of land? And with the resources

they are dealing with, they are looking at a billion barrels of oil

out of one section, but it is a terrifically expensive process to do;

and yet, there is a certain minimum. And 160 acres is probably, I

would think, in that situation too little acreage to really get an economically viable test, especially when you have two or three years.

Is that 160 acres going to be limiting for them? Or are you going

to do an EIS process to make that a larger test?

Mr. CALVERT. Well, if they were to exercise their right to expand

up to the 5,120 acres, it is our anticipation that, unless there were

a programmatic EIS in place to cover it, we would have to do sitespecific EIS’s on those 5,000-acre developments.

Whether or not they can show commercial quantities on 160

acres, the reg that we issued in June is a little vague, because it

is new territory what commercial quantities are and what commercial viability is; and essentially, put the burden on the company to

show to the authorized officer that they can produce.

It is an equation that we exercise in coal leasing, for example,

about diligence on commercial coal operations. These are functions

that the BLM can do, I am certain. It is just not something that

they have done before.

Mr. CANNON. You know, as each of the western states was

brought into the Union, each state passed, or the Federal Government passed an organic act for each state, which were almost—or

for the western states, public land states—were uniform in the obligation to do several things: set aside school trust lands; there was

an obligation to sell the public lands and give a percentage of the

proceeds of those sales, typically 5 percent, to the various states,

and that would move, of course, Federal lands into productivity,

and frankly into taxpaying status.

As Mr. Pearce has pursued this concept of how long it would take

to get this resource into production, does it make sense for the Federal Government to be thinking in terms of getting the heck out

of the business of controlling public lands and turning it over to

states?

In particular, Mr. Bishop is about to introduce a bill that would

require the Federal Government—which has not sold these public

lands, as they are mandated to do by law—to take 5 percent of the

Federal lands and turn them over to the states, probably to the

school trust lands organizations.

Does it make sense to let the states choose lands, especially in

Utah, Colorado, Wyoming, these shale oil lands, so that we can

move them into production faster than it appears that the Department is able to do?

Mr. CALVERT. Well, this is kind of a trick question.

Mr. CANNON. Oh, it’s a very straightforward question. For the

Federal Government, it may be tricky.

116

Mr. CALVERT. If a bill were to pass to convey 5 percent of the

lands to the states, then it would make sense for the states to

choose lands that were productive for oil shale, and for oil and gas,

and coal and everything else. It depends on how the bill were written.

Mr. CANNON. But of course, this is tricky because you don’t have

a departmental position on this thing yet.

Mr. CALVERT. Right.

Mr. CANNON. But I was asking your opinion. Does it make sense

for America to get these lands in a context that is a state-owned

context, so they could be developed more quickly?

Mr. CALVERT. It makes sense for America to get these lands into

a context where they can be developed, yes, sir. Whether the states

or the Federal Government can do it faster, I am not sure.

Mr. CANNON. Maybe not all states can do it faster than the Federal Government, but I can assure you that some would.

Mr. CALVERT. The State of Utah probably can.

Mr. CANNON. And with that, Mr. Chairman, I am going to yield

back. My time is almost gone, but that is a great point to turn my

time back, so I will do that.

Mr. GIBBONS. Thank you, Mr. Cannon. And we have been joined

now by Mrs. Drake. Thelma, do you have any questions that you

want to ask at this time? The floor is yours.

Mrs. DRAKE. Thank you, Mr. Chairman. I would just like to

thank all of you for being here. I truly apologize for being so late

today. But I was in the first meeting that we had on this issue;

found it very, very informative. I think what I came away with on

that one the most is that our friends in Canada have found a way

to do this, to do it efficiently, to cut through the permitting process.

My concerns are about where we are in the U.S.

You have probably already answered all of those questions, but

I think that this is a national security issue. I think that we need

to be certain that we are energy independent. I think this plays a

major part in it. And I look forward to working with you.

And if any of you have comments, that is fine. You don’t need

to comment, because I know you have already answered a lot of

questions from a lot of other people, and I am walking in right at

the last minute. Mr. Chairman, thank you for pursuing this issue.

Mr. GIBBONS. You are welcome. And Mrs. Drake does raise a

very valuable question for our Committee. I would turn to Dr.

Barna, and ask how important is it to DOD, for example, to have

a secure and reliable source of oil outside of a foreign source of oil

dependency that we are in today?

Dr. BARNA. Well, I think it is very important. If we are importing

half of our oil—and it is going to go close to 70 percent here by

2025, I believe are the estimates—we could be relying on people

that don’t necessarily have the same interests that we do and could

cause a cut. And we certainly don’t want to get where there is another limited supply, where then there have to be determinations

made on how you use that supply.

So it is very important to us. And having an indigenous, secure

supply of energy I think is certainly in the interests of the Department of Defense.

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Mr. GIBBONS. Well, when you talk about the military, how much

oil, and its products of oil, on a daily or annual basis, does the

Department of Defense consume?

Dr. BARNA. We use approximately 4 percent of the energy, the

jet fuel and the diesel that are used in the United States. So we

are really not the big dogs on the porch there. But we use enough

that we can perhaps influence——

Mr. GIBBONS. What, in terms of gallons or barrels, is that a day?

Dr. BARNA. I believe that is—let me check. About 300 to 350

thousand barrels a day, right now.

Mr. GIBBONS. That sounds like a whole lot more impressive than

just saying 4 percent; although many people out there, if they knew

the total amount of our consumption, could calculate that. Very important for you to say 350,000 barrels a day.

Dr. BARNA. And just to clarify, three-quarters of that is jet fuel.

So that is really where our impact is made in this JP-8.

Mr. GIBBONS. And do you have an estimate of how much of that

350,000-barrels-per-day consumption is produced from foreign

sources?

Dr. BARNA. I don’t. Let me see.

[Pause.]

Dr. BARNA. We buy oil worldwide. And since we import about

half of it, I assume it to be about half. But I really don’t have the

hard numbers to back that up.

Mrs. DRAKE. Mr. Chairman?

Mr. GIBBONS. Mrs. Drake.

Mrs. DRAKE. Wouldn’t he be doing what we are doing as a nation, which is about 60, 62 percent, would be foreign oil? I mean,

he doesn’t have his own source.

Dr. BARNA. Right, exactly. I would assume that since we do a

worldwide supply, that we are going to be importing—or our domestic resources would be somewhere around 50 percent, and the

other half would come from outside America.

Mr. GIBBONS. We do have a strategic defense oil reserve; do we

not?

Dr. BARNA. Yes, we do. That is under the Department of Energy,

by the way.

Mr. GIBBONS. And today, are we filling that, or drawing oil out

of it?

Mr. MADDOX. We are filling it at this point, I think.

Mr. GIBBONS. With $60-a-barrel oil?

Mr. MADDOX. That is actually royalty-in-kind oil, so it is oil coming in from the Gulf that is part of our lease payments.

Mr. GIBBONS. OK. Let me ask Mr. Maddox, in some of your publications from the Department of Energy, and indeed in some of

your comments here, you talk about the greenhouse gas emission

from the production of oil shale. Is not there a greenhouse gas

emission from the production of oil from standard oil fields?

Mr. MADDOX. Yes, there is.

Mr. GIBBONS. So in essence, what we are saying is that regardless of how we get oil out of the ground, there will be a greenhouse

gas emission?

Mr. MADDOX. That is correct.

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Mr. GIBBONS. So it really isn’t something that ought to prevent

us from stopping production of oil shale because, as you say, there

is a similar or like emission of greenhouse gases from production

of an oil well in Texas or any place, Oklahoma, or the Gulf of Mexico?

Mr. MADDOX. Yes. Emissions are a fact of life in production. In

fact, that is one of the issues Saudis are very interested in, in fact,

is trying to learn how to capture some of that for EOR and

other——

Mr. GIBBONS. Well, and also, if you look at the consumption of

unconventional oils versus conventional oil—conventional oil being

what we are talking about, Texas crude, Gulf of Mexico crude—is

there a difference in the emissions that would come from oil produced from shale, versus conventional oil?

Mr. MADDOX. I just want to confirm that, actually. It is possible

in the retort process, because of the high temperatures, you could

have a higher level of emissions than you would under conventional oil.

Mr. GIBBONS. Doesn’t a retort keep completely enclosed the environment in which the material is being heated?

Mr. MADDOX. My understanding is there are emissions; that it

does not completely enclose; that there is a certain foaming and everything else, but there is a release point.

Mr. GIBBONS. Well, because one of the things they produce right

here from this oil shale is propane. So if you had a release of propane, you have a real serious fire out there.

Mr. MADDOX. Yes.

Mr. GIBBONS. So they do control——

Mr. MADDOX. Capture, yes.

Mr. GIBBONS. They do control or capture the gases coming off of

a retort.

Mr. MADDOX. As much as they can. But traditionally, CO2 is not

captured. And that would be the issue. Now, there are uses. Again,

you know, most of these are located near gas fields and other

areas, and there is potential enhanced oil recovery use for that

CO2; which is what we are doing in a number of demonstration

projects right now.

Mr. GIBBONS. How about the in-situ recovery of oil, where it is

a down-the-hole heating of the environment? What difference

would there be from an in-situ versus a retort, with regard to

greenhouse gas emission?

Mr. MADDOX. In-situ would actually have a lower level, because

the heat and power that is generated is essentially created from an

associated gas stream that powers the local generation. So essentially, you have something more similar to a low-emission natural

gas generation facility. So you actually have a pretty low emission

level coming in an in-situ process.

Mr. GIBBONS. So somehow, they recover the CO2, then, from the

heating of the elements, or whatever power generation is required

to heat the element that is down-hole?

Mr. MADDOX. The carbon is created above the hole in the generation of electricity, which is used to heat down-hole. So there is actually no CO2, or minimal CO2 produced from in-situ.

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Mr. GIBBONS. Well, gentlemen, I commend each of you for your

testimony here today, your presence, and the interest you have

shown in what I believe is probably one of the most encouraging

oil resources that we have seen or looked at in a long time to meet

the energy needs of America.

As we know, the energy of our economy runs on oil. And the oil

shales, oil sands of this country have all of the earmarkings of an

enormously important product or process for assisting in the oil

consumption of our economy, and one which I don’t think we can

either ignore; nor do I believe we can wait long to have it developed.

I think when the American public sees $100-per-barrel oil, they

will be asking their government, ‘‘What did you do? What did you

not do, knowing that it was coming, that could have expedited the

production of oil, that could have mitigated or suppressed the perbarrel cost of oil in this country?’’

We say it is ten years off from this point, down the road. I say

it is ten years off because we lack the will power to do what is necessary to make sure that it is onboard, that it is being developed

in a commercially expedited fashion.

And I think Mr. Pearce and Mr. Cannon are right. We need a

government that looks down the road and says, ‘‘How can we make

this happen quicker?’’ We have an obstacle mentality in government, for some reason. We look at this and say, ‘‘There are so

many obstacles that we can’t overcome them quickly.’’

I think we ought to be looking at how the industry faces these

challenges. And the industry faces them from saying, ‘‘These are

obstacles that we can overcome, and we can overcome them if we

work together as a team.’’

I am pleased that the Department of Defense, the Department of

Energy, and the Department of Interior, all have a related role in

this. And every one of us, from the legislative branch to the administrative branch of government, have an obligation to see to it that

we assist in the determination of this resource as to its viability

in producing the energy sources to relieve the dependence of this

country on foreign sources of energy.

That is an obligation that you have, as well as I do. And it is

one which I take very seriously; and I hope you do, too. So I hope

that the information we have gained from this allows for us to start

thinking about: How do we expedite the process? How do we get

this to the public? So that we can avoid the $100-per-barrel catastrophe that this is going to have on the U.S. economy.

With that, Mrs. Drake, do you have any additional questions?

Mrs. DRAKE. No, thank you, Mr. Chairman.

Mr. GIBBONS. Again, I want to thank our witnesses. You have

been very good. We had planned to have us here for a little longer,

but the good luck of the Irish got you out a little early.

We will submit written questions to each of our witnesses here

today that we would like you to review and respond back to this

Committee within ten days. The record will remain open for a period of about ten days, for members to submit written questions as

well as opening statements.

With that, again, I hope you can see the interest that we have

in developing alternative and unconventional sources of energy for

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this country. And this appears to be one of the very promising

resources that we have.

And let’s hope for America that we do it right, and that we do

it expeditiously; that we do it efficiently; that we do it environmentally soundly; and that we can answer the American public’s

demand for energy in this country in a timely and economic

process.

With that, the hearing is adjourned.

[Whereupon, at 11:12 a.m., the Subcommittee was adjourned.]

[A statement submitted for the record by Dr. Robert Trent,

Former Dean, School of Mineral Engineering, University of AlaskaFairbanks, follows:]

Statement of Dr. Robert Trent, Former Dean,

School of Mineral Engineering, University of Alaska-Fairbanks

While $60.00 per barrel crude oil has generated panic-driven calls for an ‘‘alternative Energy industry,’’ hydrocarbons have begun the transition from conventional

to Non-conventional oil. The historic inclusion of oil sands in Alberta as proven reserves Of bitumen deposits assessed at 178 billion barrels is the transformative

bench-mark Between conventional and non-conventional. Expectations of a million

barrels oil Per day from Alberta’s tar sands has launched exploratory extractive and

technology Interest in other sources from China to Venezuela to Utah.

The estimated oil sand resources in the United States are in excess of 60 billion

barrels of proven and estimated reserves. In the lower 48, the majority of these reserves occur in four states: Utah, Alabama, Texas and California. Utah contains the

largest of these reserves with estimates by the U.S. Geological Survey of approximately 11.3 billion barrels. Utah contains in excess of 40% of the United States estimated reserves and approximately 60% of the measured reserves. Utah has identified 54 oil sand deposits of which 10 are considered as major.

Two of the largest Utah deposits near an infrastructure that will be required for

a timely production of the sands are Sunnyside and Asphalt Ridge. There are other

large deposits in Utah, however they are remote and will require major capital for

roads, power and pipelines. Sunnyside is the largest single oil sand deposit in the

United States and is located in the southern portion of the Unita Basin. The Sunnyside deposit was estimated by the United States Geological Survey to contain 728

million barrels of 10 to 12 API gravity oil. Asphalt Ridge is estimated by Covington

and others to contain 250 million barrels of oil.

The oil sands of the Sunnyside deposit lie on the southern flank of the Unita

Basin. Elevation of the deposit ranges from 8,500 to 10,000 feet. The oil sands are

in the upper part of the Wasatch formation and the lower part of the Green River

formation. The most significant of oil occur in the Wasatch portion of the deposit.

The saturated beds range in thickness from a few inches to more than 350 feet. Regional dip of the formation is north and east at 6 to 8 degrees. Much of the Sunnyside deposit can be surface mined and therefore offers an excellent target for economic development. The deposit is approximately eight miles from the Denver and

Rio Grand Western Railroad and about six miles north of the coal mining area of

Sunnyside. The United States Geological Survey estimates the deposit contains

1,600 million cubic yards of sands of which over 50% is commercial. Commercial

grade is considered to contain in excess of 9% bitumen. As noted above, the Geological Survey estimates the deposit to contain 728 million barrels which is described

as 450 million yards of measured and indicated material and 350 million yards as

inferred material.

Asphalt Ridge runs Northwest/Southeast for approximately 10 miles. The ridge is

approximately 3 miles from the town of Vernal Utah and is cut by highway 40. The

more erosion resistant portions of the formation form the ridge for which it is

named. The ridge is made from the Mesaverde sandstones and shales. The formation dips 8 to12 degrees to the southwest. The major bitumen saturation is in the

Tertiary and Cretaceous age beds.

The bitumen is 12 degree API gravity and extremely low in sulfur. Vernal is a

town where mining and conventional oil production is a large part of the economy

and therefore the infrastructure to support an oil sand facility is present. Although

the Asphalt Ridge deposit is not as large as Sunnyside it has received the most attention and research due to its location and infrastructure. Over the years several

121

projects have tried to produce the oil and currently there is a new 1,500 barrel/day

refinery on the north edge of Vernal that is mothballed because the operator was

not able produce enough crude using their process.

Prior research includes various compounds that act a diluents. These include diesel, hydrogen, hot water, centrifuges and solvents. In almost all cases the processes

required heat. With the current cost of natural gas the economics of many of these

processes is questionable. There have been bench scale tests of new products that

do not require heat. These bench scale tests need to be expanded to demonstrations

and pilot phases to prove the economics are favorable.

We do not believe the processes and methods used to produce bitumen in Canada

can be economical in Utah. They require large amounts of energy in the form of natural gas and water. However, U.S. tar sands (Utah) recovery could begin with less

capital ‘‘intensive and more energy-efficient recovery systems appropriate to smaller

reserve Sites. This could take place with an efficient modular reconfigurable designed recovery System approach which, with demonstrated economics, will introduce Utah tar sands As an unconventional source of oil (hydrocarbons) in diminishing American dependence On imported fuels.

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